Exhibit 99.1
  
 
  
  TABLE OF CONTENTS
  GLOSSARY OF TERMS
4SPECIAL NOTES TO READER
5Regarding Forward Looking Statements and Risk Factors
5Access to Documents
6Abbreviations and Conversions
6ARC RESOURCES LTD.
7General
7Organizational Structure
7Strategy
8Development of our Business
8Recent Developments
10STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
11Disclosure of Reserves Data
11Reserves Data – Based on Forecast Prices and Costs
11Forecast Prices and Costs
13Definitions and Notes to Reserves Data Tables
14Reconciliations of Changes in Reserves
17Future Development Costs
18Undeveloped Reserves
18Other Oil and Gas Information
20Contingent Resource Estimates
23Oil And Gas Wells
24Properties with no Attributable Reserves
24Forward Contracts
25Abandonment and Reclamation Costs
25Tax Horizon
26Capital Expenditures
26Exploration and Development Activities
27Production Estimates
28Production History
29Marketing Arrangements
30SHARE CAPITAL OF ARC RESOURCES
31Common Shares
31Preferred Shares
31OTHER INFORMATION RELATING TO OUR BUSINESS
31Borrowing
31Dividend Reinvestment and Optional Common Share Purchase Plan
32DIRECTORS AND EXECUTIVE OFFICERS
33Membership of Board Committees
35Officer Biographies
36AUDIT COMMITTEE DISCLOSURES
38Members of the Audit Committee
38Principal Accountant Fees and Services
39CONFLICTS OF INTEREST
39INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
39
  2012 Annual Information Form – ARC Resources Ltd.
Page  2
  
   DIVIDENDS AND DISTRIBUTIONS
40Dividend Policy
40Dividend History
40MARKET FOR SECURITIES
40INDUSTRY CONDITIONS
41Pricing and Marketing
41The North American Free Trade Agreement
42Royalties and Incentives
42Land Tenure
48Environmental Regulation
48Climate Change Regulation
50RISK FACTORS
51Risks Relating to Our Business and Operations
52Risk Factors Applicable to Residents of the United States and Other Non-Residents of Canada
59TRANSFER AGENT AND REGISTRAR
60MATERIAL CONTRACTS
60INTEREST OF EXPERTS
60ADDITIONAL INFORMATION
61APPENDIX A
-
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITORAPPENDIX B
-
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATIONAPPENDIX C
-
MANDATE OF THE AUDIT COMMITTEE
 2012 Annual Information Form – ARC Resources Ltd.
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 Table of Contents
 
 GLOSSARY OF TERMS
 
  In this Annual Information Form, capitalized terms shall have the meanings set forth below:
  ARC, we, us, our, Corporation or Trust means ARC Resources and all its controlled entities as a consolidated body and, prior to the completion of the Trust Conversion, the Trust and all its controlled entities as a consolidated body;
  ARC Partnership means ARC Resources General Partnership;
  ARC Resources means ARC Resources Ltd., the corporation resulting from the amalgamation of ARC Energy Ltd., ARC Resources Ltd., 1485275 Alberta Ltd., ARC Petroleum Inc. and Smiley Gas Conservation Limited which occurred pursuant to the Trust Conversion;
  COGE Handbook means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;
  Common Shares means the common shares in the capital of ARC Resources;
  Exchangeable Shares means, prior to the completion of the Trust Conversion, the series A exchangeable shares and the series B exchangeable shares of ARC Resources Ltd.;
  GLJ means GLJ Petroleum Consultants Ltd., independent petroleum consultants of Calgary, Alberta;
  GLJ Report means the report prepared by GLJ dated February 20, 2013 evaluating the crude oil, natural gas, natural gas liquids and sulphur reserves attributable to ARC's properties at December 31, 2012 and evaluating the crude oil, natural gas and natural gas liquids resources located in the NE BC Montney;
  Montney West or West Montney area means our lands west of the Dawson area in northeastern British Columbia comprised of the Sunrise, Sundown, Sunset, and Septimus areas;
  NE BC Montney means our lands in northeastern British Columbia comprised of the Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown and Blueberry areas and our lands in northwestern Alberta in the Pouce Coupe area;
  NI 51-101 means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities;
  Shareholders means holders of Common Shares of ARC Resources;
  Tax Act means the Income Tax Act (Canada);
  Trust means ARC Energy Trust, the income trust which was reorganized into ARC Resources pursuant to the Trust Conversion;
  Trust Conversionmeans the Plan of Arrangement under Section 193 of the Business Corporations Act(Alberta) involving, among others, the Trust, ARC Resources Ltd. and the security holders of the Trust and ARC Resources Ltd. which resulted in the reorganization of the Trust into a dividend paying, publicly traded exploration and production company, being ARC Resources, which together with its subsidiaries carries on the business formerly carried on by the Trust and its subsidiaries;
  Trust Units means, prior to the completion of the Trust Conversion, the units of the Trust; and
  TSX means the Toronto Stock Exchange.
  Certain other terms used in this Annual Information Form but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.
  2012 Annual Information Form – ARC Resources Ltd.
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  SPECIAL NOTES TO READER
  Regarding Forward Looking Statements and Risk Factors
  Certain statements contained in this Annual Information Form, and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements.  These statements relate to future events or our future performance.  All statements other than statements of historical fact may be forward-looking statements.  Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "budget", "plan", "continue", "estimate", "expect", "forecast", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions.  In addition there are forward looking statements in this Annual Information Form under the headings: "Statement of Reserves Data and Other Oil and Gas Information" as to our reserves and future net revenues from our reserves, pricing and inflation rates and future development costs; "Statement of Reserves Data and Other Oil and Gas Information – Other Oil and Gas Information" as to the development of our proved undeveloped reserves and probable undeveloped reserves, as to our future development activities, the status of our enhanced recovery projects, hedging policies, reclamation and abandonment obligation, tax horizon, exploration and development activities and production estimates; and under the heading "Statement of Reserves Data and Other Oil and Gas Information – Contingent Resource Estimates" as to our economic contingent resource estimates on our NE BC Montney properties.  These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.  We believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon.  These statements speak only as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be.
  In addition to the forward looking statements identified above, this Annual Information Form, and the documents incorporated by reference, contain forward-looking statements pertaining to the performance characteristics of our oil and natural gas properties; oil and natural gas production levels; the size of the oil and natural gas reserves and of our economic contingent resources, projections of market prices and costs; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; treatment under governmental regulatory regimes and tax laws; and capital expenditures programs.
  Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors.  In addition, these risks and uncertainties are material factors affecting the success of our business.  Such factors include, but are not limited to: declines in oil and natural gas prices; various pipeline constraints; the payment of dividends, if any; variations in interest rates and foreign exchange rates; uncertainties relating to the weakened global economy and consequential restricted access to capital, stock market volatility, market valuations and increased borrowing costs; refinancing risk for existing debt and debt service costs; access to external sources of capital; risks associated with our hedging activities; third party credit risk; risks associated with the exploitation of our properties and our ability to acquire reserves; government regulation and control and changes in governmental legislation; changes in income tax laws, royalty rates and other incentive programs; uncertainties associated with estimating oil and natural gas reserves and resources; risks associated with acquiring, developing and exploring for natural gas and other aspects of our operations; our reliance on hydraulic fracturing; certain of our enhanced recovery projects are not currently economically feasible;risks associated with large projects or expansion of our activities; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in climate change laws and other environmental regulations; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; risks of non-cash losses as a result of the application of accounting policies;our operating activities and ability to retain key personnel; depletion of our reserves; risks associated with securing and maintaining title to our properties; risks for United States and other non-resident Shareholders and other factors, many of which are beyond our control.
  The actual results could differ materially from those results anticipated in these forward-looking statements, which are based on assumptions, including as to the market prices for oil and natural gas; the continuation of the present policies of the Board of Directors relating to management of ARC, and the payment of dividends, capital expenditures and other matters; the continued availability of capital, acquisitions of reserves, undeveloped lands and skilled personnel; the continuation of the current tax and regulatory regime and other assumptions contained in this Annual Information Form.
  Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described can be profitably produced in the future.
  2012 Annual Information Form – ARC Resources Ltd.
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 Table of Contents
  Readers are cautioned that the foregoing lists of factors are not exhaustive.  The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement.  We do not undertake any obligation to publicly update or revise any forward-looking statements except as required by securities laws or regulations.
  Access to Documents
  Any document referred to in this Annual Information Form and described as being filed on our SEDAR profile at www.sedar.com (including those documents referred to as being incorporated by reference in this Annual Information Form) may be obtained free of charge from us at 1200, 308 – 4th Avenue SW, Calgary, Alberta, T2P 0H7.
  Abbreviations and Conversions
  Oil and Natural Gas Liquidsbbl
barrelMbbl
one thousand barrelsMMbbl
one million barrelsbbl/d
barrels per dayNGLs
natural gas liquidsNatural GasMcf
one thousand cubic feetMcf/d
one thousand cubic feet per dayMMcf
one million cubic feetMMcf/d
one million cubic feet per dayBcf
one billion cubic feetBcfe
one billion cubic feet per dayTcf
one trillion cubic feetOtherAPI
Indication of specific gravity of crude oil measured on the API gravity scaleboe
barrels of oil equivalentboe/d
barrels of oil equivalent per dayGJ
gigajoulesmboe
one thousand barrels of oil equivalent$MM
one million dollarsMMBTU
one million British Thermal Units
  We have adopted the standard of 6 Mcf:1boe when converting natural gas to boes.  Boes may be misleading, particularly if used in isolation.  A boe conversion ratio of 6 Mcf per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.  Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
  All dollar amounts set forth in this Annual Information Form are in Canadian dollars, except where otherwise indicated.
  The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).
  To Convert From
To
Multiply Bycubic metres
cubic feet
35.315bbls
cubic metres
0.159cubic metres
bbls
6.290Feet
metres
0.305Metres
feet
3.281Miles
kilometres
1.609Kilometres
miles
0.621Acres
hectares
0.4047Hectares
acres
2.471
 
 
  2012 Annual Information Form – ARC Resources Ltd.
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 ARC RESOURCES LTD.
  General
  ARC Resources was formed by amalgamation under the Business Corporations Act (Alberta).  Prior to January 1, 2011, ARC was one of Canada's largest conventional oil and gas royalty trusts.
  Currently, ARC is one of Canada’s leading conventional oil and gas companies with average production in 2012 of 93,546 boe per day.  ARC’s business activities include the exploration, development and production of crude oil, natural gas and natural gas liquids in five core areas across western Canada. Founded in 1996, ARC has focused on the acquisition and development of resource rich properties that provide an option for both near-term and long-term growth.  ARC trades on the Toronto Stock Exchange under the symbol ARX and currently pays a monthly dividend to its Shareholders.
  As of the end of 2012, ARC had approximately 545 employees with 320 professional, technical and support staff in the Calgary office and 225 individuals located across ARC’s operating areas in western Canada.
  Our principal office is located at 1200, 308 – 4th Avenue SW, Calgary, Alberta, T2P 0H7 and our registered office is located at 2400, 525 – 8th Avenue SW, Calgary, Alberta, T2P 1G1.
  Organizational Structure
  The ARC Partnership owns substantially all of our oil and natural gas properties and is owned 100 per cent directly or indirectly by ARC Resources.  ARC Resources is the manager of the ARC Partnership.  The ARC Partnership is a general partnership formed under the laws of Alberta.
  The following diagram sets forth the organizational structure of ARC:
  GRAPHIC
 2012 Annual Information Form – ARC Resources Ltd.
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 Strategy
  ARC’s vision is to be a leading energy producer, focused on the delivery of results through our strategy of risk-managed value creation.ARC is committed to providing superior long-term financial returns for our shareholders; creating a culture where respect for the individual is paramount and action and passion is rewarded; and to running our business in a manner that protects the safety of employees, communities and the environment. ARC’s vision is realized through the four pillars of our strategy:
  1.
High quality, long-life assets.  ARC’s unique suite of assets includes growth assets and base assets.  ARC’s growth assets consist of world-class resource play properties, primarily concentrated in the Montney geological formation in northeast British Columbia and northern Alberta, and in the Cardium formation in the Pembina area of Alberta. These assets provide substantial growth opportunities, which ARC will pursue with a clear line of sight towards long-term profitable development.  ARC’s base assets consist of core properties located throughout Alberta, Saskatchewan and Manitoba.  The base assets deliver stable production, have relatively low decline rates and contribute significant cash flow to fund future growth.
 
 2.
Operational excellence. ARC is focused on capital discipline and cost management to target the maximum return on its investments. Production from individual oil and natural gas wells naturally declines over time. In any one year, ARC approves a budget to drill new wells with the intent to first replace production declines and second to potentially increase production volumes.   At times, ARC may also acquire strategic producing or undeveloped properties to enhance current production and reserves or to provide potential future drilling locations.  Alternatively, we may strategically dispose of non-core assets that no longer meet our investment criteria.
 
 3.
Financial flexibility. ARC provides returns to shareholders through a combination of a monthly dividend, currently $0.10 per share per month, and a potential for capital appreciation.  ARC chooses to maintain prudent debt levels and a strong balance sheet; targeting its net debt to be one to 1.5 times annualized funds from operations and less than 20 per cent of total capitalization over the long-term.ARC’s goal is to fund capital expenditures necessary to replace production declines and dividend payments from funds from operations.  ARC will finance growth activities through a combination of sources, including funds from operations, proceeds from ARC’s Dividend Reinvestment and Optional Cash Payment Program (“DRIP”), proceeds from property dispositions and debt and equity issuances.  In addition, ARC’s risk management program actively hedges to provide stability to a portion of funds from operations.
  4.
Top talent and strong leadership culture.  ARC is committed to the attraction, retention and development of the best and brightest people within its organization.  ARC’s employees conduct business every day in a culture of trust, respect, integrity and accountability.  Building leadership talent at all levels of the organization is a key focus. ARC is also committed to corporate leadership through community investment, environmental reporting practices and open-communication with all stakeholders.
 
 Development of our Business
  A description of the general development of our business over the last three financial years follows:
  2010
  Production was a record 73,954 boe/d while funds from operations were $667.0 million.
  Distributions to investors were maintained at $0.10 per Trust Unit per month throughout the year resulting in a total of $313.5 million being distributed.
  On January 5, 2010, the Trust closed an equity offering and issued 13 million Trust Units at $19.40 per unit.  The net proceeds of the offering were $239.5 million and were used to reduce our bank indebtedness following the $178.9 million acquisition of assets in the Ante Creek area which closed in the middle of December 2009.
  On August 17, 2010, ARC Resources Ltd. acquired all of the existing and outstanding common shares of Storm Energy Inc. ("Storm") pursuant to a plan of arrangement under the provisions of Section 192 of the Canada Business Corporations Act involving Storm, Storm Resources Ltd., the Trust and ARC Resources Ltd. (the "Storm Arrangement").  The transaction was valued at approximately $652.1 million (including the assumption of debt) based on the August 17, 2010 closing price of $19.53 per Trust Unit.  Storm's primary asset was the Parkland field in northeastern British Columbia, a Montney gas field located approximately ten kilometres from ARC's Dawson field.  Production from the Storm assets averaged 7,800 boe per day over the last four months of 2010.
   2012 Annual Information Form – ARC Resources Ltd.
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  Pursuant to the Storm Arrangement, the Trust issued 23,003,154 Trust Units and ARC Resources issued 1,924,997 series B exchangeable shares (which shares, as at the closing date, were exchangeable for 5,439,098 Trust Units) to holders of Storm shares and assumed approximately $96.7 million of total net debt.
  Capital expenditures were $1,248.0 million, of which $652.1 million was the Storm Arrangement, $489.9 million (39 per cent) was development and facility capital expenditures; $81.9 million (seven per cent) was property acquisition costs, geological and geophysical expenditures, and drilling costs for exploratory wells.  $24.1 million was spent on corporate leasehold costs for new office space.
  In the second quarter, ARC started up the 60 MMcf/d Dawson Phase 1 gas plant.
  2011
  The Trust Conversion was completed on January 1, 2011 and resulted in the reorganization of the Trust into ARC Resources, a new publicly traded exploration and development corporation formed upon the amalgamation of ARC Energy Ltd., ARC Resources Ltd., 1485275 Alberta Ltd., ARC Petroleum Inc. and Smiley Gas Conservation Limited.
  In accordance with the terms of the Trust Conversion, the holders ("Unitholders") of Trust Units of the Trust received, through a series of steps, one Common Share of ARC Resources for each Trust Unit held and the holders of Exchangeable Shares of ARC Resources Ltd. received, through a series of steps, 2.89162 Common Shares of ARC Resources for each Exchangeable Share held, such number being the exchangeable share ratio of the Exchangeable Shares as at December 31, 2010.  In addition, pursuant to the Trust Conversion, the Trust was dissolved and ARC Resources acquired all of the assets of the Trust and ARC Resources assumed all of the liabilities of the Trust.
  Following the Trust Conversion, ARC Resources, together with its subsidiaries, carries on the business formerly carried on by the Trust and its subsidiaries.
  The Common Shares of ARC Resources began trading on the TSX under the trading symbol ARX on January 6, 2011.  Beginning with the payment of dividends to Shareholders of ARC of record on January 31, 2011, Shareholders of ARC receive payments in the form of dividends.  Prior to the conversion of the Trust to a corporation on December 31, 2010, distributions were paid to unitholders.  Previous historical references to "unitholders", "distributions" "trust units", and "per unit" have now been replaced by "Shareholders", "dividends", "Common Shares", and "per share", respectively where applicable.
  Despite the change in legal structure from a trust to a dividend paying corporation, ARC's business activities and business strategy remained unchanged and the board of directors and officers at the time of the Trust Conversion remained the same.
  Production was a record 83,416 boe/d while funds from operations were $844.3 million.
  Dividends to investors were maintained at $0.10 per share per month throughout the year resulting in a total of $344.0 million being distributed.
  In the second quarter of 2011, ARC commissioned the 60 MMcf/d Dawson Phase 2 gas plant, increasing operated plant capacity at Dawson from 60 MMcf/d to 120 MMcf/d.  Dawson production increased to 165 MMcf/d during 2011, with 120 MMcf/d processed at the ARC gas plants and 45 MMcf/d processed at third party facilities.
  Capital expenditures were $726 million, of which $585.3 million (81 per cent) was development and facility capital expenditures, $74.9 million was spent to acquire land, $52.3 million were on geological and geophysical expenditures and drilling costs for exploratory wells, the remaining $13.5 million was for corporate capital spending.
  During 2011, ARC divested of certain non-core properties for proceeds of $170 million plus 36 sections of land in the Ante Creek region.
  ARC renegotiated and extended its syndicated revolving credit facility to a four year term in 2011.  ARC had total credit capacity of $1.6 billion at December 31, 2011.  Net debt to annualized year-to-date funds from operations ratio was 1.1 times and net debt was approximately 11 per cent of ARC's total capitalization at the end of 2011; both well within our target levels.
   2012 Annual Information Form – ARC Resources Ltd.
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  2012
  Production was a record 93,546 boe/d while funds from operations were $719.8 million.
  Dividends paid to investors were maintained at $0.10 per share per month throughout the year resulting in a total of $357.4 million being distributed of which $117.4 million was reinvested into Common Shares through the DRIP.
  Despite the reduction in the 2012 capital budget from $760 million to actual 2012 capital spending of $608 million, ARC achieved its production guidance and increased crude oil and liquids production 15 per cent relative to 2011. Capital expenditures were $429.8 million (71 per cent) on drilling and completions, $131.6 million (22 per cent) on plant and facilities, $31.8 million on geological and geophysical expenditures, $9.5 million on undeveloped crown land, and the remaining on other corporate capital spending.  In addition, ARC spent $36.5 million on ‘tuck-in’ acquisitions in key areas ($32.4 million net of non-core property dispositions).
  In February 2012, ARC commissioned a new 30 MMcf/d Ante Creek gas plant which resulted in production from the Ante Creek field increasing from 8,000 boe per day prior to the commissioning of the plant to 10,500 boe per day by the end of the second quarter.   Late in 2012, ARC received all regulatory approvals to construct 120 MMcf/d of gas processing and liquids handling facilities in the Parkland/Tower area.  The plant has a designed capacity to handle up to 130 bbls of oil and liquids per MMcf.  The construction of the first 60 MMcf/d phase of the facility commenced in late 2012.  ARC expects the first phase to be on-stream in early 2014.
  On August 22, 2012, ARC issued 14.6 million Common Shares at $23.65 per share for net proceeds of $330.9 million. The proceeds will be used to pay down existing debt, thereby freeing up capacity that can be put towards the 2013 capital program, and at December 31, 2012, contributed to ARC’s working capital surplus of $41.8 million.
  On August 23, 2012, ARC issued US $360 million and Cdn $40 million of long-term fixed rate notes through a private placement to secure additional credit capacity by paying down indebtedness under ARC’s credit facility and to capitalize on low long-term interest rates. The notes have an average term of 9.6 years and bear interest at an average rate of 3.8 per cent.
  ARC extended its syndicated revolving credit facility for one additional year until August 3, 2016 at existing terms.  At December 31, 2012, ARC had total unutilized credit capacity of $1.2 billion.  At the end of 2012, net debt to annualized funds from operations ratio was one times and net debt was approximately nine per cent of ARC’s total capitalization; both metrics well within target levels.
  Recent Developments
  Effective January 1, 2013 ARC implemented the following organizational changes.  John Dielwart retired from the position of Chief Executive Officer and has agreed to stay on as an advisor through to the Annual and Special Meeting of Shareholders to be held on May 15, 2013 to assist with the transition and remains on the Board of Directors.   Myron Stadnyk was appointed President and Chief Executive Officer and as a member of the Board of Directors.  Mr. Stadnyk has been with ARC since 1997 and has held the position of President and Chief Operating Officer since February 2009.  Cam Kramer was promoted to the position of Senior Vice-President and Chief Operating Officer.  Mr. Kramer joined ARC in 2011 as Senior Vice-President, Operations.
  ARC’s Board of Directors has approved the implementation of a Stock Dividend Program (the “SDP”), subject to shareholder approval at the Annual and Special Meeting of Shareholders to be held on May 15, 2013.  While the SDP is similar in financial effect to ARC’s existing dividend reinvestment program, the SDP has certain income tax attributes which may make it more attractive to some shareholders.  The SDP will be offered to both Canadian and non-Canadian shareholders.  Further details regarding the SDP will be outlined in the Information Circular – Proxy Statement which will be filed on our SEDAR profile at www.sedar.com.  ARC’s DRIP will, subject to a number of amendments which will be made to the existing plan, continue as a complement to the SDP.
   2012 Annual Information Form – ARC Resources Ltd.
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  STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
  Disclosure of Reserves Data
  The statement of reserves data and other oil and gas information is set forth below (the "Statement").  The effective date of the Statement is December 31, 2012 and the preparation date of the Statement is January 15, 2013. The reserves data conforms to the requirements of NI 51-101.
  The reserves data set forth below is based upon an evaluation by GLJ  and contained in the GLJ Report dated February 20, 2013.  The reserves data summarizes our oil, liquids and natural gas reserves and the net present values of future net revenue for these reserves, using forecast prices and costs prior to provision for interest, general and administrative expenses, the impact of any hedging activities or the liability associated with certain abandonment and well, pipeline and facilities reclamation.  Future net revenues have been presented on a before and after tax basis.  We engaged GLJ to provide an evaluation of proved and proved plus probable reserves.
  All of our reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba.
  It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.  There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material.  The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.  Readers should review the definitions and information contained in "Definitions and Notes to Reserves Data Tables" in conjunction with the following tables and notes.  For more information as to the risks involved, see "Risk Factors – Risk Relating to Our Business and Operations".
  The Report on Reserves Data by GLJ on Form 51-102F2 and the Report of Management and Directors on Reserves Data and Other Information on Form 51-101F3 are attached as Appendices A and B to this Annual Information Form.
   Reserves Data – Based on Forecast Prices and Costs
  Summary of Oil and Gas Reserves – Based on Forecast Prices and CostsCompany Gross

Reserves

Light &

Medium

Crude Oil

(Mbbl)


Heavy

CrudeOil

(Mbbl)


Total

Crude Oil

(Mbbl)


NGLs

(Mbbl)


Natural

Gas

(Bcf)


Total2012

(mboe)PROVEDDeveloped Producing


88,539



1,739



90,278



9,578



607



201,018Developed

Non-Producing


1,973



-



1,973



1,260



53



12,044Undeveloped


14,743



-



14,743



9,375



760



150,841TOTAL PROVED


105,255



1,739



106,994



20,214



1,420



363,904Probable


41,187



517



41,704



16,637



1,108



243,078TOTAL PROVED

PLUS PROBABLE


146,442



2,256



148,698



36,850



2,529



606,982
   2012 Annual Information Form – ARC Resources Ltd.
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   Summary of Oil and Gas Reserves – Based on Forecast Prices and CostsCompany Net

Reserves

Light &Medium

Crude Oil

(Mbbl)


Heavy

Crude Oil

(Mbbl)


TotalCrude Oil

(Mbbl)


NGLs

(Mbbl)


NaturalGas

(Bcf)


Total2012

(mboe)PROVEDDeveloped Producing


77,035



1,724



78,759



7,135



513



171,415Developed

Non-Producing


1,688



-



1,688



1,038



45



10,188Undeveloped


13,010



-



13,010



7,870



641



127,711TOTAL PROVED


91,733



1,724



93,457



16,043



1,199



309,314Probable


35,235



512



35,747



13,352



899



198,867TOTAL PROVED

PLUS PROBABLE


126,967



2,236



129,203



29,235



2097



508,180
 
  Net Present Value of Future Net Revenues - Based on Forecast Prices and CostsBefore Tax

Undiscounted

($MM)


Discounted

at 5%

($MM)


Discounted

at 10%

($MM)


Discounted

at 15%

($MM)


Discounted

at 20%

($MMPROVEDDeveloped Producing


5,887



4,163



3,249



2,686



2,305Developed

Non-Producing


333



234



179



145



122Undeveloped


2,369



1,321



767



441



234TOTAL PROVED


8,539



5,719



4,195



3,272



2,661Probable


6,253



3,123



1,843



1,205



841TOTAL PROVED

PLUS PROBABLE


14,842



8,841



6,039



4,477



3,502After Tax(1)(2)PROVEDDeveloped Producing


4,985



3,582



2,829



2,360



2,039Developed

Non-Producing


249



175



133



107



90Undeveloped


1,771



942



500



240



76TOTAL PROVED


7,005



4,699



3,462



2,707



2,205Probable


4,675



2,302



1,330



844



569TOTAL PROVED PLUS PROBABLE


11,680



7,001



4,792



3,552



2,774
  Notes:
 (1)
Based on ARC’s estimated tax pools at year-end 2012.
  2012 Annual Information Form – ARC Resources Ltd.
Page  12
 Table of Contents
  (2)
The after-tax net present value of ARC's oil and gas properties presented here reflect the income tax burden on the properties on a stand-alone basis.  It does not consider the business-entity-level tax situation, or tax planning.  It does not provide an estimate of the net present value at the level of the business entity, which may be significantly different.  ARC's audited consolidated financial statements for the year ended December 31, 2012 and the related Management's Discussion and Analysis should be consulted for information at the business entity level.
  Total Future Net Revenue (Undiscounted) – Based on Forecast Prices and CostsReserves

Category

Revenue

($MM)


Royalties

($MM)


Operating Costs

($MM)


Development Costs

($MM)


Abandonment and

Reclamation Costs

($MM)


Future

Net

Revenue Before Income Taxes

($MM)


Income Taxes

($MM)


Future

Net

Revenue After

IncomeTaxes

($MM)Proved Reserves


20,082



2,963



6,269



1,970



292



8,589



1,584



7,005Proved Plus Probable Reserves


33,299



5,247



9,485



3,380



346



14,842



3,162



11,680
 
 Future Net Revenue By Production Group – Based on Forecast Prices and CostsReserves Category
Production Group

Future Net Revenue

BeforeIncome Taxes

(Discounted at

10% per year)

($MM)

Per Unit(3)Proved Reserves
Light and Medium Crude Oil (1)


2,509

$22.54/bblHeavy Oil (1)


44

$27.58/bblNatural Gas (2)


1,643

$1.39/McfTotal


4,195Proved Plus Probable Reserves
Light and Medium Crude Oil (1)


3,286

$20.60/bblHeavy Oil (1)


55

$26.62/bblNatural Gas (2)


2,698

$1.30/McfTotal


6,039
  Notes:
 (1)
Including solution gas and other by-products.
 (2)
Including by-products but excluding solution gas.
 (3)
Unit values are based on Company Net Reserves.
  Forecast Prices and Costs
  These are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date.  To the extent that there are fixed or presently determinable future prices or costs to which we are legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs shall be incorporated into the forecast prices.
  2012 Annual Information Form – ARC Resources Ltd.
Page  13
 Table of Contents
 The forecast cost and price assumptions include increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs.  Crude oil, natural gas and natural gas liquids benchmark reference pricing as at December 31, 2012, and inflation and exchange rates utilized in the GLJ Report were as follows:
  Summary of Forecast Prices and Inflation Rate AssumptionsOil


Natural

Gas


Edmonton Liquids PricesWTI Cushing Oklahoma

($US/bbl)


Edmonton Par Price 40° API

($Cdn/bbl)


Hardisty Heavy 12° API

($Cdn/bbl)


Cromer Medium 29.3 API

($Cdn/bbl)


AECO

Gas

Price ($Cdn/

MMbtu)


Propane

($Cdn/bbl)


Butane

($Cdn/bbl)


Pentanes Plus ($Cdn/bbl)


Inflation Rate(1) %/Year


Exchange Rate(2) ($US/$Cdn)Forecast2013


90.00



85.00



60.92



79.90



3.38



34.06



65.45



96.63



2.0



1.002014


92.50



91.50



68.36



84.18



3.83



45.75



70.46



97.91



2.0



1.002015


95.00



94.00



71.10



86.48



4.28



56.40



72.38



97.76



2.0



1.002016


97.50



96.50



73.02



88.78



4.72



57.90



74.31



100.36



2.0



1.002017


97.50



96.50



73.02



88.78



4.95



57.90



74.31



100.36



2.0



1.002018


97.50



96.50



73.02



88.78



5.22



57.90



74.31



100.36



2.0



1.002019


98.54



97.54



73.81



89.74



5.32



58.52



75.11



101.44



2.0



1.002020


100.51



99.51



75.32



91.55



5.43



59.71



76.62



103.49



2.0



1.002021


102.52



101.52



76.87



93.40



5.54



60.91



78.17



105.58



2.0



1.002022


104.57



103.57



78.44



95.28



5.64



62.14



79.75



107.71



2.0



1.00Thereafter


(3
)


(3
)


(3
)


(3
)


(3
)


(3
)


(3
)


(3
)


2.0



1.00
  Notes:
 (1)
Inflation rates for forecasting costs.
 (2)
Exchange rates used to generate the benchmark reference prices in this table.
 (3)
Prices escalate 2.0 per cent per year from 2022.
  ARC’s weighted average prices realized for the year ended December 31, 2012, were $2.62/Mcf for natural gas, $82.40/bbl for light and medium crude oil, $68.45/bbl for heavy crude oil and $62.55/bbl for natural gas liquids including condensate.  Only a minor amount of our production is characterized as heavy oil.
  Definitions and Notes to Reserves Data Tables
  In the tables set forth above and elsewhere in this Annual Information Form the following definitions and other notes are applicable:
  1.
"Gross" means:
  (a)
in relation to our interest in production and reserves, our interest (operating and non-operating) before deduction of royalties and without including any royalty interest of us;
  (b)
in relation to wells, the total number of wells in which we have an interest; and
  (c)
in relation to properties, the total area of properties in which we have an interest.
  2.
"Net" means:
  (a)
in relation to our interest in production and reserves, our interest (operating and non-operating) after deduction of royalty obligations, plus our royalty interest in production or reserves;
  2012 Annual Information Form – ARC Resources Ltd.
Page  14
 Table of Contents
  (b)
in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and
  (c)
in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we owned.
  3.
Columns may not add due to rounding.
  4.
Estimated future well abandonment costs related to reserves wells have been taken into account by GLJ in determining the aggregate future net revenue therefrom.
  5.
The forecast price and cost assumptions assumed the continuance of current laws and regulations.
  6.
All factual data supplied to GLJ was accepted as represented.  No field inspection was conducted.
  7.
The crude oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the CSA Notice 51-324 – Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities and the COGE Handbook.  A summary of those definitions are set forth below:
 Reserves Categories
  Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions.
  Reserves are classified according to the degree of certainty associated with the estimates.
  (a)
Proved reservesare those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
  (b)
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
  Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.
  Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:
  (a)
Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production.  The developed category may be subdivided into producing and non-producing.
  (i)
Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate.  These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
  (ii)
Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
  (b)
Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production.  They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
 In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-
 
 2012 Annual Information Form – ARC Resources Ltd.
Page  15
 Table of Contents
 
 
 producing.  This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
  Levels of Certainty for Reported Reserves
  The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented).  Reported reserves should target the following levels of certainty under a specific set of economic conditions:
  (a)
at least a 90 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
  (b)
at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.
  A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties.  However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability.  In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
  Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.
  2012 Annual Information Form – ARC Resources Ltd.
Page  16
 Table of Contents
  Reconciliations of Changes in Reserves
  The following table sets forth the reconciliation of our gross reserves as at December 31, 2012, using forecast price and cost estimates derived from the GLJ Report.  Gross reserves as at December 31, 2012 and as at December 31, 2011 include working interest reserves before royalties payable and without including gross royalties receivable.
  Reconciliation of Gross Reserves By Principal Product TypeLight and

MediumCrude

(Mbbl)


Heavy

Crude Oil

(Mbbl)


Total

Crude Oil

(Mbbl)


NGLs

(Mbbl)


NaturalGas

(Bcf)


Total

(mboe)PROVEDDecember 31, 2011


102,188



1,874



104,062



19,088



1,418.9



359,641Discoveries


-



-



-



7



0.3



54Extensions and

Improved  Recovery(1)


11,676



167



11,843



1,989



62.5



24,246Technical Revisions


3,591



(44
)


3,547



2,282



224.2



43,196Acquisitions


359



-



359



12



0.2



411Dispositions


-



-



-



(142
)


(4.0
)


(806
)Economic Factors


(1,425
)


(13
)


(1,438
)


(1,222
)


(157.4
)


(28,891
)Production


(11,134
)


(245
)


(11,379
)


(1,800
)


(124.6
)


(33,947
)December 31, 2012


105,255



1,739



106,994



20,214



1420.2



363,904PROBABLEDecember 31, 2011


32,883



434



33,317



13,686



994.4



212,733Discoveries


-



-



-



2



0.1



15Extensions and

Improved Recovery (1)


7,388



111



7,499



1,097



47.1



16,437Technical Revisions


454



(32
)


422



1,869



(25.1
)


(1,895
)Acquisitions


553



-



553



216



6.6



1,864Dispositions


-



-



-



(61
)


(1.6
)


(335
)Economic Factors


(91
)


4



(87
)


(172
)


87.1



14,261Production


-



-



-



-



-



-December 31, 2012


41,187



517



41,704



16,637



1,108.4



243,079PROVED PLUS PROBABLEDecember 31, 2011


135,071



2,308



137,379



32,774



2,413.3



572,374Discoveries


-



-



-



9



0.4



68Extensions and

Improved Recovery (1)


19,064



278



19,342



3,086



109.5



40,683Technical Revisions


4,045



(76
)


3,969



4,150



199.1



41,301Acquisitions


912



-



912



228



6.8



2,275Dispositions


-



-



-



(203
)


(5.6
)


(1,141
)Economic Factors


(1,516
)


(9
)


(1,525
)


(1,394
)


(70.3
)


(14,631
)Production


(11,134
)


(245
)


(11,379
)


(1,800
)


(124.6
)


(33,947
)December 31, 2012


146,442



2,256



148,698



36,850



2,528.6



606,982
  Notes:
 (1)
Reserve additions for Infill Drilling, Extensions and Improved Recovery are combined and reported as ‘Extensions and Improved Recovery’.
 
 2012 Annual Information Form – ARC Resources Ltd.
Page  17
 Table of Contents
 
  Future Development Costs
  The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserves categories noted below:
  Future Development CostsYear

Proved Reserves

($MM)


Proved Plus

Probable Reserves

($MM)2013


467.7



600.62014


518.0



809.32015


491.7



641.12016


279.0



457.82017


104.5



352.3Remainder


108.7



519.0Total: Undiscounted


1,969.6



3,380.1Total: Discounted at 10%/year


1,589.3



2,592.6
 
 We expect to fund the development costs of the reserves through a combination of funds from operations, debt, the sale of existing less-strategic assets and the issuance of Common Shares.
 
 Estimates of reserves and future net revenue have been made assuming the development of each property, in respect of which the estimate is made, will occur, without regard to the likely availability to us of funding required for the development.  There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the GLJ Report.  Failure to develop those reserves would have a negative impact on future funds from operations.
 
 The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized.  We do not anticipate that interest or other funding costs would make development of any property uneconomic.
  Undeveloped Reserves
  Undeveloped reserves are attributed by GLJ in accordance with standards and procedures contained in the COGE Handbook.  Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.  Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.
  The following tables disclose by each product type the volumes of proved and probable undeveloped reserves that were first attributed by GLJ in each of the most recent three financial years and, in the aggregate, before that time.
  2012 Annual Information Form – ARC Resources Ltd.
Page  18
 Table of Contents
  Proved Undeveloped ReservesLight &Medium Oil

(Mbbl)

Heavy Oil

(Mbbl)

Natural GasLiquids

(Mbbl)

NaturalGas

(MMcf)

Total

(mboe)First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

EndPrior


8,655



8,655



-



-



2,636



2,636



388,364



388,364



76,018



76,0182010


4,299



11,085



30



30



4,259



6,193



223,762



543,518



45,882



107,8942011


5,405



12,768



-



-



2,620



8,122



209,126



719,277



42,880



140,7702012


5,572



14,743



-



-



915



9,375



43,103



760,334



13,671



150,840
  Probable Undeveloped ReservesLight &Medium Oil

(Mbbl)

Heavy Oil

(Mbbl)

Natural GasLiquids

(Mbbl)

NaturalGas

(MMcf)

Total

(mboe)First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

End


First

Attributed


Total

at

Year-

EndPrior


10,435



10,435



100



100



2,083



2,083



299,771



299,771



62,580



62,5802010


7,477



12,523



-



150



2,589



4,768



155,242



439,484



35,940



90,6892011


4,299



10,976



-



-



6,205



10,667



350,542



787,242



68,927



152,8502012


7,946



18,581



61



61



1,638



13,314



54,306



890,847



18,696



180,431
  As of December 31, 2012, undeveloped reserves represented 41 per cent of total proved reserves and 55 per cent of proved plus probable reserves.  Over 85 per cent of the proved plus probable undeveloped reserves are located in the NE BC / NW AB district.  We have planned a program for the development of a portion of the undeveloped reserves in 2013.
  We plan to develop the majority of the proved undeveloped reserves in the reserves evaluation over the next four years and plan to develop the majority of the probable undeveloped reserves over the next six years.  The pace of development of these reserves is influenced by many factors, including the ongoing development of the infrastructure in the Attachie and Montney West areas, the outcomes of the yearly drilling and reservoir evaluations, the price for oil and natural gas, and a variety of economic factors.
  There are a number of factors that could result in delayed or cancelled development, including the following:  (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access, issues (including those relating to land owners, weather conditions and regulatory approvals).  For more information, see "Risk Factors – Risk Relating to Our Business and Operations".
 
 Significant Factors or Uncertainties
  We have a significant amount of proved undeveloped and probable undeveloped reserves assigned to the NE BC Montney.  Sophisticated and expensive technology and large capital expenditures are required to bring these undeveloped reserves into production.
  Degradation in future commodity price forecasts relative to the forecast in the GLJ Report can also have a negative impact on the economics of the development of undeveloped reserves, unless significant reduction in the future costs of development are realized.
  2012 Annual Information Form – ARC Resources Ltd.
Page  19
 Table of Contents
  Other Oil and Gas Information
  Principal Districts
  The following is a description of our principal oil and natural gas districts as at December 31, 2012.  Reserves amounts are stated at December 31, 2012, based on escalated cost and price assumptions as evaluated in the GLJ Report prepared by GLJ (see "Statement of Reserves Data and Other Oil and Gas Information").  Information in respect of gross and net acres and well counts are as at December 31, 2012, and information in respect of production is for the year ended December 31, 2012 except where indicated otherwise.  Due to the fact that we have been active at acquiring additional interests in our principal properties, the working interest share and interest in gross and net acres and wells as at December 31, 2012 may not directly correspond to the stated production for the year, which only includes production since the date the interests were acquired by us.  The estimate of reserves for individual properties and/or districts may not reflect the same confidence level as estimates for all properties, due to the effects of aggregation.
  All of the districts described below are located in the Western Canadian Sedimentary Basin and within the Canadian provinces of British Columbia, Alberta, Saskatchewan or Manitoba.  The districts described below comprise 100 per cent of the total gross proved plus probable reserves as assigned by GLJ in the GLJ Report.  Approximately 62 per cent of total gross proved plus probable reserves for the described districts are located in the Province of British Columbia.  Except as set forth under the heading "Statement of Reserves Data and Other Oil and Gas Information – Other Oil and Gas Information – Proved and Probable Undeveloped Reserves", there are no other material districts to which reserves have been attributed that are capable of producing but which are not producing at December 31, 2012 and there are no material statutory or mandatory relinquishments, surrenders, back-ins or changes in ownership provisions.  When determining gross and net acreage for two or more lease agreements covering the same lands but different rights, the acreage is reported for each lease agreement.
  2012 Company Gross Reserves and Company Gross ProductionLight & Medium

CrudeOil


Heavy

Oil


Natural

Gas


NaturalGas

Liquids


Total Oil Equivalent Production(1)


Proved

Reserves


Proved Plus

ProbableReserves(bbl/d)


(bbl/d)


(MMcf/d)


(bbl/d)


(boe/d)


(mboe)


(mboe)


(%)NE BC /

NW AB


1,012



0



240.7



2,125



43,252



205,404



388,404



64.0Northern AB


5,866



31



39.2



1,455



13,886



36,991



59,014



9.7Pembina


7,260



118



16.8



936



11,107



43,018



55,514



9.2South Central


4,836



520



42.9



323



12,830



43,990



55,913



9.2SE Sask /

Manitoba


11,446



0



0.9



79



11,675



34,501



48,137



7.9Total


30,420



669



340.5



4,918



92,750



363,904



606,982



100.0
  Notes:
 (1)
Production volumes as disclosed above are “gross production” which is our interest (operated and non-operated) in production before deduction of royalties and without including any royalty interests to us.  These volumes differ from the “company interest production” volumes disclosed in this Annual Information Form under “ARC Resources Ltd. - Development of our Business” and “Statement of Reserves Data and Other Oil and Gas Information – Production History” as well as in our audited consolidated financial statements for the year ended December 31, 2012 and the related Management’s Discussion and Analysis which is our interest (operated and non-operated) in production before deduction of royalties and including royalty interests.
 
 2012 Annual Information Form – ARC Resources Ltd.
Page  20
 Table of Contents
 
  
  NE BC / NW AB
  ARC’s assets in northeast British Columbia and northwest Alberta are located in the Montney resource play. The Montney is recognized as one of the best tight gas plays in North America with both dry and liquids-rich gas. ARC was an early entrant in the Montney, and pioneered the use of multi-stage fracturing for horizontal completions; a technology that has proved instrumental in unlocking the play. Today, ARC is the third largest operator in the region and has expanded its land holdings to over 400 net Montney sections.   The Montney is a key growth area with significant potential for continued reserves and production additions. In 2012, the gross proven plus probable reserves assigned by GLJ for the district were 388,404 mboe or 64 per cent of the total reserves of the Corporation. The GLJ Report estimates the drilling of 401 operated proved undeveloped and probable locations will be needed to achieve production of these reserves.
  During 2012, ARC continued the successful development and delineation of various liquids-rich areas spending $174 million, or 29 per cent of its 2012 capital development program in this district.  ARC has an average operating ownership of 76 per cent in approximately 262,101 gross hectares (198,157 net hectares).  Key operating areas include Dawson, Tower, Parkland and Sunrise/Septimus where ARC drilled and participated in 19 gross wells in 2012 with approximately an 87 per cent working interest. ARC is positioned to meaningfully grow natural gas, natural gas liquids, and oil production in the near-term with the commencement of the gas processing plant and liquid extraction facilities at Parkland/Tower of which phase one is scheduled to be operational in early 2014.
  Northern AB
  ARC’s holdings in Northern Alberta are characterized by long-life reserves and have significant potential for continued growth and development.  Key properties include Ante Creek and Swan Hills.  ARC’s Ante Creek property is located within the oil prone Montney formation and produces a mixture of oil, natural gas and natural gas liquids.  The district was a prime focus in 2012 whereby $148 million or 24 per cent of the 2012 capital program was spent, primarily at Ante Creek, with 22 wells drilled with 100 per cent working interest.  The Corporation has an average operating ownership of 81 per cent in approximately 208,248 gross hectares (167,722 net hectares).  In 2012, GLJ assigned gross proved reserves of 36,991 mboe and gross proved plus probable reserves of 59,014 mboe of oil, natural gas and natural gas liquids, representing 9.7 per cent of total gross proved plus probable reserves to this district.  The GLJ Report estimates the drilling of 95 operated proved undeveloped and probable locations will be needed to achieve production of these reserves.
  Ante Creek remains a core focus area for ARC as we plan to spend approximately $132 million to drill 34 gross operated horizontal oil wells in 2013.  As ARC increases oil production at Ante Creek, we will continue to fill the 30 MMcf/d operated gas processing plant with solution gas. During 2013, ARC will optimize capital efficiencies with the execution of pad drilling programs and continued assessment of optimal well spacing. The shift to pad drilling will
 
 2012 Annual Information Form – ARC Resources Ltd.
Page 21
 Table of Contents
 
 result in production staying relatively flat for the first eight or nine months of 2013 with large acceleration of growth once the first pad comes on production in the fall of 2013.
  Pembina
  The Pembina Cardium field was discovered in 1953. ARC has been a core holder in the area since the ARC’s inception in 1996 and today is its second largest operator. The field is characterized by its long-reserve life, high netback and high quality oil, and proximity to refining facilities. Reservoir management is a key focus for ARC in maximizing recovery through optimization of the water flood.  The application of horizontal technology in the region is reviving this 60 year old asset.
  During 2012, ARC spent $114 million or approximately 19 per cent of the capital development program in this district and increased production to an average of 11,107 boed.  Key properties in the area include the Berrymoor Cardium Unit (73.3 per cent unit interest), Lindale Cardium Unit (55.3 per cent unit interest), MIPA (100 per cent working interest) and the North Pembina Cardium Unit (45.6 per cent unit interest).  ARC has an average operating ownership of 53 per cent in approximately 113,323 gross hectares (59,544 net hectares).  In 2012, GLJ assigned gross proved reserves of 43,018 mboe and gross proved plus probable reserves of 55,514 mboe of oil, natural gas and natural gas liquids to this district, representing 9.2 per cent of total gross proved plus probable reserves.  The GLJ Report estimates the drilling of 82 operated proved undeveloped and probable locations will be needed to achieve production of these reserves.
  South Central
  The South Central assets produce low cost shallow gas and medium to light crude oil.  ARC’s South Central assets reach from Redwater, Alberta to Crane Lake, Saskatchewan encompassing one of Canada’s largest historical shallow gas producing regions. This area provides ARC with stable production characterized as low decline and low risk.During 2012, ARC spent $20 million or approximately 3 per cent of the capital development program in this district.  ARC has an average operating ownership of 66 per cent in approximately 351,282 gross hectares (231,441 net hectares).  GLJ assigned gross proved reserves of 43,990 mboe and gross proved plus probable reserves of 55,913 mboe of oil, natural gas and natural gas liquids to this district, representing 9.2 per cent of total gross proved plus probable reserves.  The GLJ Report estimates the drilling of 68 operated proved undeveloped and probable locations will be needed to achieve the production of these reserves.
   Redwater is the largest property by production in the district at approximately 3,800 boed. Oil and solution gas are processed at a central operated facility. During 2012, ARC continued production operations at the EOR pilot project in Redwater. The pilot was designed to confirm whether the Redwater reef is amenable to CO2 flooding and if incremental oil can be mobilized and recovered. The CO2 injection phase of the pilot has been completed, while the observation of producing wells continues. Prior to commercial operations, large amounts of CO2 need to be acquired on economic terms for the Redwater EOR project to proceed. There is no assurance that the Redwater EOR project will proceed to a commercial phase or become economically viable.
  SE Sask /Manitoba
 
 The southeast Saskatchewan and Manitoba properties produce high netback, light crude oil.  Located in the Williston basin, ARC’s assets span over 350 kilometres from Landscape, Saskatchewan to Goodlands, Manitoba.  Key properties in the area include Lougheed, Weyburn Unit (6.9 per cent unit interest), Midale Unit (15.5 per cent unit interest) and Goodlands. ARC has excellent exposure to enhanced oil recovery projects at the Weyburn Unit and Midale Unit CO2 floods.
  During 2012, ARC spent $134 million or approximately 22 per cent of the capital development program in this district.  The 2012 capital spend in this region was concentrated at the Goodlands property, a light oil play located in southwestern Manitoba. The Goodlands property affords ARC some of the best drilling economics in the portfolio. ARC has an average operating ownership of 81 per cent in approximately 76,594 gross hectares (62,224 net hectares). GLJ assigned gross proved reserves of 34,501 mboe and gross proved plus probable reserves of 48,137 mboe of oil, natural gas and natural gas liquids, representing 7.9 per cent of total gross proved plus probable reserves to this district.  The GLJ Report estimates the drilling of 86 operated proved undeveloped and probable locations will be needed to achieve production of these reserves.
  2012 Annual Information Form – ARC Resources Ltd.
Page  22
 Table of Contents
 
 Contingent Resource Estimates
  ARC engaged GLJ to provide an updated evaluation of, among other things, our Economic Contingent Resources (as defined below) for our working interest in our NE BC Montney properties, effective December 31, 2012.  We own an average 91 per cent working interest in our NE BC Montney properties.  The evaluation procedures employed by GLJ are in compliance with standards contained in the COGE Handbook and the GLJ Report is based on GLJ's January 1, 2013 pricing.  See "Statement of Reserves Data and Other Oil and Gas Information - Forecast Prices and Costs".
  The estimates of Economic Contingent Resources should not be confused with reserves and readers should review the definitions and notes set forth below.  Actual crude oil, natural gas, and natural gas liquids resources may be greater than or less than the estimates provided herein.  There is no certainty that it will be commercially viable to produce any portion of the resources.
  Estimated Economic Contingent Resource (1)(2)Best

Estimate(3)Natural Gas (Tcf)


4.2Natural Gas Liquids (MMbbls)


111.2Oil (MMbbls)


12.6
  Notes:
 (1)
"Contingent Resources" are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.  Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets.  It is also appropriate to classify as "Contingent Resources" the estimated discovered recoverable quantities associated with a project in the early evaluation stage.  Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be sub classified based on project maturity and/or characterized by their economic status.  "Economic Contingent Resources" are those Contingent Resources that are currently economically recoverable.
 (2)
Based on the GLJ Report and effective as of December 31, 2012 and based on Company Gross Volumes.
 (3)
"Best Estimate" is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will actually be recovered.  It is equally likely that the actual remaining quantities recovered will be greater or less than the Best Estimate.  If probabilistic methods are used, there should be 50 per cent probability (P50) that the quantities actually recovered will equal or exceed the Best Estimate.
 
 Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in order for Economic Contingent Resources to be recovered in the future.  The principal risks that would inhibit the recovery of additional resources relate to the potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop the resources, low natural gas, natural gas liquids, and oil prices that would curtail the economics of development, the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fracturing technology and applications.
  In the NE BC Montney, the contingencies that prevent the Economic Contingent Resources from being classified as reserves are associated with the early evaluation stage of these potential development opportunities.  Additional drilling, completion and results are generally required before ARC can commit to their development.
  Projects have not been defined to develop the resources in the NE BC Montney as at the evaluation date.  Such projects, in the case of the NE BC Montney, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, ARC’s short-term and long-term view of natural gas, natural gas liquids and oil prices, the results of exploration and development activities of ARC and others in the area and infrastructure capacity constraints.
  For more information, see "Risk Factors – Risk Relating to our Business and Operations – There are numerous uncertainties inherent in estimating quantities of recoverable oil and gas reserves and resources including many factors beyond our control".
  2012 Annual Information Form – ARC Resources Ltd.
Page  23
 Table of Contents
  Oil And Gas Wells
  The following tables set forth the number and status of wells in which we had a working interest as at December 31, 2012.
  By District

Oil Wells


Natural Gas WellsProducing


Non-Producing


Producing


Non-ProducingGross


Net


Gross


Net


Gross


Net


Gross


NetNE BC/ NW AB


227



58



103



19



638



303



220



150Northern AB


741



296



303



112



136



66



109



66Pembina


1,289



664



291



111



242



64



42



11South Central


759



636



132



106



4,178



2,586



259



142SE SK/ MB


2,440



932



314



101



1



1



0



0Total


5,456



2,585



1,143



450



5,195



3,020



630



369
 
  By Province

Oil Wells


Natural Gas WellsProducing


Non-Producing


Producing


Non-ProducingGross


Net


Gross


Net


Gross


Net


Gross


NetAlberta


2,820



1,535



808



334



3,241



1,910



403



197British Columbia


11



8



2



1



262



241



133



112Saskatchewan


1,993



859



307



99



1,692



870



94



60Manitoba


632



183



26



16



0



0



0



0Total


5,456



2,585



1,143



450



5,195



3,020



630



369
 
 Properties with no Attributable Reserves
  The following table sets out by district our undeveloped land holdings as at December 31, 2012.
  Undeveloped HectaresGross


NetNE BC / NW AB


145,023



116,039Northern AB


175,810



114,795Pembina


27,968



14,735South Central


65,820



47,046SE SK/ MB


37,889



31,997Total


452,510



324,612
 
 Undeveloped hectares are lands that have not been assigned reserves; however, in certain of our undeveloped lands, reserves may have been assigned in shallower formations.
  We currently have no material work commitments on these lands.  There are no material expiries in our core holdings in 2013.
  2012 Annual Information Form – ARC Resources Ltd.
Page  24
 Table of Contents
  Forward Contracts
  We are exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations.  ARC maintains a Risk Management program to reduce the volatility of revenues, increase the certainty of funds from operations, and to protect acquisition and development economics.
  We may also potentially be exposed to losses in the event of default by the counterparties to these derivative instruments.  We manage this risk by diversifying our derivative portfolio among a number of financially sound counterparties and by monitoring their ongoing credit risks.
  ARC’s Risk Management program is governed by certain guidelines approved by the Board of Directors. These guidelines permit hedging up to a maximum of 55 per cent of forecasted production on a boe basis for up to two years. Specifically for natural gas, the guidelines permit additional hedging of 25 per cent of forecasted production beyond year two and up to five years. Further to these authorizations, the Board of Directors may approve hedging higher percentages of forecasted production or longer term hedging transactions to mitigate risks relating to, and protecting the economics of major capital expenditures, including acquisitions. We have a Risk Committee of the Board of Directors that reviews policies, procedures and provides oversight to management in the areas of financial and business risks including activities related to our hedging program.
  A summary of financial and physical contracts in respect of hedging activities can be found in Note 15 "Financial Instruments and Market Risk Management" to our audited consolidated financial statements for the year ended December 31, 2012 and in the section under the heading "Risk Management and Hedging Activities" in our Management's Discussion and Analysis for the year ended December 31, 2012 which have been filed on our SEDAR profile at www.sedar.com, and both of which note and section are incorporated in this Annual Information Form by reference.
  Abandonment and Reclamation Costs
  The following table sets forth information respecting future abandonment and reclamation costs for surface leases, wells, facilities and pipelines which we expect to incur for the periods indicated.
  Abandonment & ReclamationCosts escalated at 2.0%

Undiscounted

($MM)


Discounted at 10%

($MM)Total as at December 31, 2012


1,386.2



64.3Anticipated to be paid in 2013


2.1



1.9Anticipated to be paid in 2014


3.0



2.8Anticipated to be paid in 2015


2.3



2.0
  We will be liable for our share of ongoing environmental obligations and for the ultimate reclamation of the properties held by us upon abandonment.  We estimate that we have an interest in 8,432 net wells that will require abandonment and/or reclamation over the next 60 years with the majority of payments being made in years 2060 to 2072.  These ongoing environmental obligations are expected to be funded with funds from operations.
  We currently estimate that the future abandonment and reclamation obligations in respect of our properties will be approximately $1,386.2 million calculated by escalating costs at two per cent per year (reflected in our audited consolidated financial statements as an asset retirement obligation of $532.9 million calculated by escalating costs at two per cent per year and discounting at a blended rate of 2.5 per cent).  For more information, see Note 13 of our audited consolidated financial statements for the year ended December 31, 2012 and the section in our Management's Discussion and Analysis of such financial statements under the heading "Asset Retirement Obligations and Reclamation Fund", which note and section are incorporated in this Annual Information Form by reference and are found on our SEDAR profile at www.sedar.com.  During 2012, $11.9 million ($8.4 million for 2011) of actual expenditures were expended on abandonment and reclamation activities.
  ARC’s estimated liability associated with well, pipelines, facilities and reclamation costs which was not included by GLJ in estimating future net revenue in the GLJ Report is $1,040.2 million (escalating costs at two per cent and undiscounted) and $7.3 million (escalating costs at two per cent and discounted at  ten per cent).  Only the abandonment costs associated with wells with reserves were deducted by GLJ in estimating future net revenue.
  2012 Annual Information Form – ARC Resources Ltd.
Page  25
 Table of Contents
  We have committed to a restricted reclamation trust associated with the acquisition of the Redwater property pursuant to which ARC has agreed with the vendor of the Redwater property to contribute to such trust certain minimum amounts, totaling approximately $110 million over a 50 year period, to fund future environmental and reclamation obligations in respect of the Redwater properties, or to expend certain minimum amounts towards discharging these obligations.  The restricted reclamation trust commenced in 2006 with an initial contribution of $6.1 million.  In accordance with the trust agreement, ARC has contributed total funds of $37 million to the restricted reclamation fund as at December 31, 2012.  Contributions to the trust will continue at a declining rate through 2055.  The balance of the restricted reclamation trust was $29.8 million at December 31, 2012.
  We estimate the costs to abandon and reclaim all our shut-in and producing wells, pipelines and facilities.  No estimate of salvage value is netted against the estimated cost.  Our model for estimating the amount and timing of future abandonment and reclamation expenditures was created on an operating area level.  Estimated expenditures for each operating area are benchmarked from numerous sources including the provincial regulatory agencies, industry peer groups, third party engineering firms and actual data from our operations.  All wells, pipelines, facilities and associated costs are then assigned to a specific geographic region which is consistent with the methodology used by the Energy Resources Conservation Board.
  Abandonment and reclamation costs have been estimated over a 60 year period.  Facility abandonment and reclamation costs are scheduled to be incurred in the year following the end of the reserves life of its associated reserve.
 
 Tax Horizon
  We expect to allocate our funds from operations among funding a portion of capital expenditures, periodic debt repayments, site reclamation expenditures, and cash payments to Shareholders in the form of dividends. Taxable income varies depending on total income and expenses and varies with changes to commodity prices, costs, claims for both accumulated tax pools and tax pools associated with current year expenditures.
  ARC has accumulated $2.3 billion of income tax pools for federal tax purposes.  These tax pools reflect the application of partnership deferral rules. There is a deferral of partnership income of $51.6 million inherent in the income tax calculation for the year ended December 31, 2012. This deferral, as available under Canadian income tax legislation, utilizes $118 million of the $2.3 billion of income tax pools.  For the first time in ARC’s history, ARC recognized current income taxes in 2012, and also expects to recognize current income taxes in 2013.
  Capital Expenditures
  The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) related to our activities for the year ended December 31, 2012:
  2012 Capital ExpendituresNE BC /

NW AB

($MM)


NorthernAB

($MM)


Pembina

($MM)


SouthCentral

($MM)


SE SK /MB

($MM)


Corporate

($MM)


Total

($MM)Property Acquisition Costs(1)Proved Properties


12.1



9.3



6.6



-



0.6



-



28.6Undeveloped Properties


2.4



1.4



-



-



-



-



3.8Exploration Costs(2)


39.4



4.7



-



2.9



3.4



-



50.4Development Costs(3)


135.0



143.1



114.2



17.0



130.5



-



539.8Corporate Capital Costs


-



-



-



-



-



17.8



17.8Total


188.9



158.5



120.8



19.9



134.5



17.8



640.4
  Notes:
 (1)
Represents acquisition costs net of dispositions and property swaps.
 (2)
Includes costs of land acquired ($5.0 million), geological and geophysical capital expenditures and drilling costs for 2012 exploration wells drilled.
 (3)
Includes costs of land acquired ($4.5 million), development and facilities capital expenditures and drilling costs for 2012 development wells drilled.
  2012 Annual Information Form – ARC Resources Ltd.
Page  26
 Table of Contents
  Exploration and Development Activities
  The following tables set forth the gross and net exploratory and development wells that we participated in during the year ended December 31, 2012:
  By District

Exploratory Wells


Development Wells


TotalGross


Net


Gross


Net


Gross


NetNE BC / NW AB


2



2



17



14



19



16Northern AB


4



4



32



23



36



27Pembina


1



1



85



35



86



36South Central


0



0



1



1



1



1SE Sask/ MB


0



0



99



67



99



67Total


7



7



234



140



241



147
  By Well Type

Exploratory Wells


Development Wells


TotalGross


Net


Gross


Net


Gross


NetLight & Medium Oil


0



0



209



130



209



130Heavy Oil


0



0



0



0



0



0Natural Gas


3



3



7



5



10



8Service


4



4



16



4



20



8Dry


0



0



2



1



2



1Total


7



7



234



140



241



147
  For 2013, ARC Resources has planned an extensive capital program of $830 million.  The program is directed primarily at oil and liquids-rich gas opportunities at Tower in British Columbia, Ante Creek and Pembina in Alberta, Goodlands in Manitoba and various oil properties in southeast Saskatchewan.  Our capital program is subject to variation throughout the year depending upon prices for oil and natural gas and other factors and there is no assurance that all or any part of our capital program will be expended as planned.  In addition, capital expenditures may be made on the acquisition of undeveloped land or oil and natural gas reserves.  See "Risk Factors – Risk Relating to our Business and Operations".
  2012 Annual Information Form – ARC Resources Ltd.
Page  27
 Table of Contents
  Production Estimates
  The following tables sets out the volume of production estimated for the year ended December 31, 2013 which is reflected in the estimate of gross proved reserves and gross probable reserves disclosed in the tables contained under "Statement of Reserves Data and Other Oil and Gas Information - Disclosure of Reserves Data".
  TOTAL PROVEDLight &Medium Oil

(bbl/d)


Heavy Oil

(bbl/d)


Natural Gas

(Mcf/d)


Natural GasLiquids

(bbl/d)


Total

(boe/d)Gross


Net


Gross


Net


Gross


Net


Gross


Net


Gross


NetDawson


0



0



0



0



143,635



121,986



711



610



24,650



20,940Other Properties


28,484



24,573



721



749



162,190



144,369



4,185



3,223



60,423



52,606Total Proved


28,484



24,573



721



749



305,825



266,355



4,896



3,833



85,072



73,547
 
  TOTAL PROBABLELight &Medium Oil

(bbl/d)


Heavy Oil

(bbl/d)


Natural Gas

(Mcf/d)


Natural GasLiquids

(bbl/d)


Total

(boe/d)Gross


Net


Gross


Net


Gross


Net


Gross


Net


Gross


NetDawson


0



0



0



0



13,151



11,571



65



57



2,257



1,987Other Properties


2,746



2,313



65



60



14,928



13,164



636



521



5,933



5,088Total Probable


2,746



2,313



65



60



28,079



24,735



701



578



8,190



7,075
 
  TOTAL PROVED PLUS PROBABLELight &Medium Oil

(bbl/d)


Heavy Oil

(bbl/d)


Natural Gas

(Mcf/d)


Natural GasLiquids

(bbl/d)


Total

(boe/d)Gross


Net


Gross


Net


Gross


Net


Gross


Net


Gross


NetDawson


0



0



0



0



156,786



133,557



776



667



26,907



22,927Other Properties


31,230



26,886



786



809



177,118



157,533



4,821



3,744



66,356



57,694Total Proved Plus Probable


31,230



26,886



786



809



333,903



291,090



5,597



4,411



93,263



80,621
 
 The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
  2012 Annual Information Form – ARC Resources Ltd.
Page  28
 Table of Contents
   Production History
  The following tables summarize certain information in respect of our production, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:
  Production History

Quarter Ended


Year2012


EndedMar. 31


June 30


Sept. 30


Dec. 31


2012Average Daily Production(1)Light and Medium Crude Oil (bbl/d)


30,451



29,931



29,920



32,114



30,620Heavy Oil (bbl/d)


854



900



812



824



834Gas (MMcf/d)


353.0



347.2



323.2



348.2



324.9Natural Gas Liquids (bbl/d) (2)


4,831



5,294



4,912



4,745



4,945Condensate (bbl/d)


2,399



2,381



2,325



1,767



2,217NGLs (bbl/d) (3)


2,432



2,913



2,587



2,978



2,728Total (boe/d)


94,970



93,997



89,511



95,725



93,546Average Net Production Prices ReceivedLight and Medium Crude Oil ($/bbl)


87.56



79.46



81.86



80.89



82.40Heavy Oil ($/bbl)


75.76



63.12



65.68



65.07



68.45Gas ($/Mcf)


2.67



2.03



2.45



3.32



2.62Natural Gas Liquids ($/bbl) (2)


72.02



65.20



57.84



54.96



62.55Condensate ($/bbl)


99.96



94.60



87.65



86.70



92.63NGLs ($/bbl) (3)


44.46



41.17



31.05



36.13



38.11Total ($/boe)


42.39



37.15



40.06



42.62



40.58Royalties PaidLight and Medium Crude Oil ($/bbl)


15.46



13.34



11.31



12.44



12.94Heavy Oil ($/bbl)


9.59



6.76



5.90



5.92



7.17Gas ($/Mcf)


0.16



0.08



0.06



0.23



0.15Natural Gas Liquids ($/bbl) (2)


20.05



17.90



15.21



13.43



16.50Condensate ($/bbl)


27.32



25.46



24.23



22.87



25.18NGLs ($/bbl) (3)


12.87



11.71



7.10



7.82



9.44Total ($/boe)


6.65



5.58



4.89



5.71



5.72Operating Expenses (4)(5)Light and Medium Crude Oil ($/bbl)


14.13



15.25



16.25



16.18



15.13Heavy Oil ($/bbl)


17.71



14.62



20.11



22.52



18.67Gas ($/Mcf)


0.80



0.82



1.02



0.77



1.03Natural Gas Liquids ($/bbl) (2)


6.53



8.34



10.34



7.91



9.38Condensate ($/bbl)


4.23



6.73



6.59



6.99



8.41NGLs ($/bbl) (3)


8.80



9.66



13.70



8.45



10.17Total ($/boe)


8.75



9.48



10.64



8.80



9.40Transportation PaidLight and Medium Crude Oil ($/bbl)


0.70



0.92



1.62



1.35



1.15Heavy Oil ($/bbl)


1.08



1.25



0.71



0.78



0.98Gas ($/Mcf)


0.25



0.25



0.26



0.21



0.24Natural Gas Liquids ($/bbl) (2)


0.98



0.74



0.61



0.92



0.81Condensate ($/bbl)


1.58



1.07



0.52



1.37



1.12NGLs ($/bbl) (3)


0.38



0.48



0.68



0.65



0.55Total ($/boe)


1.18



1.23



1.49



1.26



1.29(Loss)/Gain on Commodity ContractsLight and Medium Crude Oil ($/bbl)


(5.00
)


0.11



0.52



3.51



(0.16
)Heavy Oil ($/bbl)


-



-



-



-



-Gas ($/Mcf)


0.44



0.95



0.72



0.01



0.53Natural Gas Liquids ($/bbl) (2)


-



-



-



-



-Condensate ($/bbl)


-



-



-



-



-NGLs ($/bbl) (3)


-



-



-



-



-Total ($/boe)


-



3.54



2.79



1.26



1.87
  2012 Annual Information Form – ARC Resources Ltd.
Page  29
 Table of Contents
  
 Production History

Quarter Ended

2012


Year

EndedMar. 31



June 30



Sept. 30



Dec. 31



2012Netback Received(6)Light and Medium Crude Oil ($/bbl)


52.27



50.06



53.20



54.43



53.02Heavy Oil ($/bbl)


47.38



40.49



38.96



35.85



41.63Gas ($/Mcf)


1.90



1.83



1.83



2.12



1.73Natural Gas Liquids ($/bbl) (2)


66.83



61.34



56.31



55.47



57.92Condensate ($/bbl)


22.41



19.32



9.57



19.21



17.95NGLs ($/bbl) (3)


44.46



38.22



31.68



32.70



35.86Total ($/boe)


25.81



24.40



25.83



28.11



26.04
  Notes:
 (1)
Before deduction of royalties and including royalty interests.
 (2)
Natural Gas Liquids as defined by GLJ which includes condensate, butane, ethane and propane.
 (3)
NGLs or natural gas liquids as defined by ARC in external reporting which includes butane, ethane and propane but excludes condensate.
 (4)
Operating expenses are composed of direct costs incurred to operate both oil and gas wells.  A number of assumptions have been made in allocating these costs between oil, natural gas and natural gas liquids production.
 (5)
Operating recoveries associated with operated properties were excluded from operating costs and accounted for as a reduction to general and administrative costs.
 (6)
Netbacks are calculated by subtracting royalties, operating expenses, transportation costs, and losses/ (gains) on commodity contracts from revenues.
  The NE BC/NW AB, Northern AB, Pembina, South Central and SE SK/MB districts account for approximately 46 per cent, 15 per cent, 12 per cent, 13 per cent and 14 per cent, respectively, of the total production disclosed above. For more information, see "Statement of Reserves Data and Other Oil and Gas Information – Other Oil and Gas Information".
  Marketing Arrangements
  Natural Gas
  During 2012, we continued our marketing strategy of maintaining a high level of direct control and diversification of marketing and transportation arrangements for our natural gas production.
  The average natural gas price we received during 2012 was $2.62 per Mcf before hedging as compared to $3.83 per Mcf before hedging for 2011.  This price was achieved with a portfolio mix that on average through the year received AECO index based pricing for 74 per cent, Western Canadian Station 2 index based pricing for 16 per cent, aggregator netback prices for two per cent, and Chicago index pricing for eight per cent of total production.
  Our natural gas sales portfolio is directed towards liquid markets and pricing terms that allow us to reduce price volatility and to stabilize the revenue stream.  We also strive for a high utilization of contracted pipeline and processing capacity.
 
 Crude Oil and Natural Gas Liquids
  Our liquids production in 2012 was comprised of approximately 54.5 per cent light quality crude oil (greater than 35°API), 26.5 per cent medium quality crude oil (25 to 35 API), 3.5 per cent heavy quality crude (less than 25°API) and15.5 per cent condensate and natural gas liquids.
  During 2012, our average sales prices were $82.40 per bbl for light and medium crude oil, $68.45 per bbl for heavy crude oil and $62.55 per bbl for condensate and natural gas liquids; these prices compare to 2011 prices of $90.05 per bbl for light and medium crude oil, $73.29 per bbl for heavy crude oil and $69.68 per bbl for condensate and natural gas liquids.
  During 2012, increases in Canadian and United States oil supply, higher than normal refinery outages, and pipeline bottlenecks in the United States resulted in significantly lower prices for Canadian producers relative to the WTI price for crude oil.  This price decrease has resulted in our inability to realize the full economic potential of some of our production.  See "Risk Factors – Risk Relating to Our Business and Operations – Gathering and processing facilities and pipeline systems are subject to certain risks and in certain circumstances may adversely affect the amounts realized by us for our oil and natural gas".
  2012 Annual Information Form – ARC Resources Ltd.
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 Our crude oil is sold under contracts of varying terms of up to one year, based on market sensitive pricing terms. Approximately half of ARC’s natural gas liquids are sold on a multi-year contract until April 1, 2015; the remaining volume is sold under annual arrangements.  Industry pricing benchmarks for crude oil and natural gas liquids are continuously monitored to ensure optimal netbacks.
  SHARE CAPITAL OF ARC RESOURCES
  The authorized capital of ARC Resources is an unlimited number of Common Shares without nominal or par value (defined in this Annual Information Form as "Common Shares") and 50,000,000 preferred shares without nominal or par value issuable in series of which 308,888,285 Common Shares and no preferred shares are outstanding as at December 31, 2012.
  The following is a summary of the rights, privileges, restrictions and conditions which attach to the securities of ARC Resources.
  Common Shares
  Holders of Common Shares are entitled to notice of, to attend and to one vote per share held at any meeting of the Shareholders of the Corporation (other than meetings of a class or series of shares of the Corporation other than the Common Shares as such).
  Holders of Common Shares are entitled to receive dividends as and when declared by the board of directors of the Corporation on the Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends attached to shares of other classes of shares of the Corporation ranking in priority to the Common Shares in respect of dividends.
  Holders of Common Shares are entitled in the event of any liquidation, dissolution or winding-up of the Corporation, whether voluntary or involuntary, or any other distribution of the assets of the Corporation among its Shareholders for the purpose of winding-up its affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of shares of the Corporation ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of shares of the Corporation ranking equally with the Common Shares in respect of return of capital on dissolution, in such assets of the Corporation as are available for distribution.
  Preferred Shares
  Preferred shares may at any time or from time-to-time be issued in one or more series.  Before any shares of a particular series are issued, the Board shall, by resolution, fix the number of shares that will form such series and shall, subject to the limitations set out in ARC Resources' articles, by resolution fix the designation, rights, privileges, restrictions and conditions to be attached to the preferred shares of such series, including, but without in any way limiting or restricting the generality of the foregoing, the rate, amount or method of calculation of dividends thereon, the time and place of payment of dividends, the consideration for and the terms and conditions of any purchase for cancellation, retraction or redemption thereof, conversion or exchange rights (if any), and whether into or for securities of ARC Resources or otherwise, voting rights attached thereto (if any), the terms and conditions of any share purchase or retirement plan or sinking fund, and restrictions on the payment of dividends on any shares other than preferred shares or payment in respect of capital on any shares in the capital of ARC Resources or creation or issue of debt or equity securities.  Notwithstanding the foregoing, other than in the case of a failure to declare or pay dividends specified in any series of preferred shares, the voting rights attached to the preferred shares shall be limited to one vote per preferred share at any meeting where the preferred shares and Common Shares vote together as a single class.
  The preferred shares of ARC Resources are intended to provide future financing flexibility and are not intended to be used to block any takeover bid for ARC Resources.  ARC Resources confirms that it will not, without prior shareholder approval, issue any preferred shares for any anti-takeover purpose.
  OTHER INFORMATION RELATING TO OUR BUSINESS
  Borrowing
  We borrow funds periodically to finance the purchase of properties, for capital expenditures or for other financial obligations or expenditures in respect of properties held by us or for working capital purposes.  ARC’s long-term strategy is to target debt between one and 1.5 times funds from operations and debt under 20 per cent of total
 
 2012 Annual Information Form – ARC Resources Ltd.
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  capitalization.   The level of borrowing is assessed on a weekly basis by management and is subject to quarterly reviews by the Board of Directors of ARC Resources.
  Our credit facilities are comprised of both a bank credit facility and long-term notes issued to major financial institutions.  We may choose to repay a portion of our debt from one source and borrow from other parties in order to reduce borrowing costs and provide more financial flexibility. Debt repayment will be scheduled to the extent possible to minimize any income tax payable by ARC Resources.
  As at December 31, 2012, we had credit facilities consisting of a Cdn $1 billion, financial covenant based credit facility with a syndicate of major chartered banks, a Cdn $25 million working capital facility with its agent bank, a Cdn $25 million letter of credit facility with its agent bank, and US $727.9 million and Cdn $63.2 million of senior notes outstanding.  An additional amount of US $128.1 million of senior notes was available to be issued pursuant to a US $225 million Master Shelf Agreement with a large insurance company (the "Master Shelf").  ARC had a net debt balance of Cdn $745.6 million outstanding at December 31, 2012, comprised of Cdn $787.4 million of long-term debt and a working capital surplus of Cdn $41.8 million.
  Borrowings under the syndicated credit facility bear interest at bank prime or, at ARC's option, Canadian dollar bankers' acceptances or U.S. dollar LIBOR loans plus a stamping fee.  At the option of ARC, the lenders will review the credit facility each year and determine whether they will extend the revolving four year period for another year.  In the event the credit facility is not extended at any time before the maturity date, the loan will become repayable on the maturity date. On October 22, 2012, the credit facility was extended for another year at the same terms as the existing facility.  The current maturity date of the credit facility is August 3, 2016.
  ARC Resources has the option to draw the remaining credit capacity pursuant to the Master Shelf at any time.  This option was renewed on April 14, 2012  and expires in April 2015.  ARC Resources may issue senior notes at a rate equal to the related U.S. treasuries corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. The senior notes outstanding were issued in 11 tranches and bear interest at a fixed rate.  Each tranche requires certain repayments of principal prior to the final maturity thereof.
  The following are significant financial covenants governing the revolving credit facilities:
  —
Long-term debt and letters of credit not to exceed three times trailing twelve month net income before non-cash items, income tax and interest expense;
  —
Long-term debt, letters of credit and subordinated debt not to exceed four times trailing twelve month net income before non-cash items, income tax and interest expense; and
  —
Long-term debt and letters of credit not to exceed 50 per cent of Shareholders' equity and long-term debt, letters of credit and subordinated debt.
 ARC Resources is in compliance in all material respects with the terms of the agreements governing the credit facilities described above.
  The credit facilities and senior notes rank equally and contain provisions which restrict the payment of dividends to Shareholders, in the event of the occurrence of certain events of default.  The syndicated credit agreement, the note agreements and master shelf agreement are described under "Material Contracts" and have been filed on our SEDAR profile at www.sedar.com.  For more information, reference is made to Note 12 of our audited consolidated financial statements for the year ended December 31, 2012, which note is incorporated by reference in this Annual Information Form and which has been filed on our SEDAR profile at www.sedar.com.
  See "Risk Factors – Risk Relating to Our Business and Operations".
  Dividend Reinvestment and Optional Common Share Purchase Plan
  A plan has been established to provide Shareholders who are residents of Canada (within the meaning of the Tax Act) with a method to reinvest dividends by purchasing additional Common Shares.
  2012 Annual Information Form – ARC Resources Ltd.
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  DIRECTORS AND EXECUTIVE OFFICERS
  The name and municipality of residence, positions held and principal occupation of each director and officer of ARC Resources as at December 31, 2012 are set out below:
  DirectorsName and Municipality of

Residence
Office Held and Time

as Director (2)
Principal OccupationMac H. Van Wielingen(1)

Calgary, Alberta, Canada
Chairman of the Board and

Director since May 3, 1996
Co-Chairman of ARC Financial Corporation

(an investment management company)Walter DeBoni

Calgary, Alberta, Canada
Vice Chairman and Director since

June 26, 1996
Independent BusinessmanJohn P. Dielwart

Calgary, Alberta, Canada
Chief Executive Officer and

Director since May 3, 1996
Chief Executive Officer of ARC ResourcesFred J. Dyment

Calgary, Alberta, Canada
Director since April 17, 2003
Independent BusinessmanTimothy J. Hearn

Calgary, Alberta, Canada
Director since June 22, 2011
Independent BusinessmanJames C. Houck

Calgary, Alberta, Canada
Director since February 14, 2008
Independent BusinessmanHarold N. Kvisle

Calgary, Alberta Canada
Director since May 20, 2009
President and Chief Executive Officer of

Talisman Energy Inc.Kathleen M. O'Neill

Toronto, Ontario, Canada
Director since June 1, 2009
Independent BusinesswomanHerbert C. Pinder, Jr.

Saskatoon, Saskatchewan,

Canada
Director since January 1, 2006
Independent Businessman
  Notes:
 (1)
Mr. Van Wielingen is the Chairman and a Director of ARC Resources and was a director of Gauntlet Energy Corporation that secured creditor protection pursuant to the Companies’ Creditors Arrangement Act on June 17, 2003 and was subsequently acquired by Ketch Resources Ltd. in December 2003.
 (2)
The term of each director is until the next annual meeting of ARC Resources, which is scheduled to be held on May 15, 2013.
 
  On January 1, 2013, Mr. Dielwart retired as Chief Executive Officer of ARC Resources but remains as a director. On January 1, 2013, Myron M. Stadnyk was promoted from President and Chief Operating Officer to President and Chief Executive Officer and was appointed as a director.
  2012 Annual Information Form – ARC Resources Ltd.
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 Executive OfficersName and Municipality of

Residence
Office Held
Principal OccupationJohn P. Dielwart(1)

Calgary, Alberta, Canada
Chief Executive Officer
Chief Executive Officer of ARC ResourcesMyron M. Stadnyk(2)

Calgary, Alberta, Canada
President and Chief Operating

Officer
President and Chief Operating Officer of ARC ResourcesSteven W. Sinclair

Calgary, Alberta, Canada
Senior Vice-President and Chief

Financial Officer
Senior Vice-President and Chief Financial Officer of

ARC ResourcesCameron S. Kramer(3)

Calgary, Alberta, Canada
Senior Vice-President, Operations
Senior Vice-President, Operations of ARC

ResourcesDavid P. Carey

Calgary, Alberta, Canada
Senior Vice-President, Capital

Markets
Senior Vice-President, Capital Markets of

ARC ResourcesTerry Gill

Calgary, Alberta, Canada
Senior Vice-President, Corporate

Services
Senior Vice-President, Corporate Services

of ARC ResourcesTerry M. Anderson(4)

Calgary, Alberta, Canada
Senior Vice-President, Engineering
Senior Vice-President, Engineering of ARC

ResourcesP. Van R. Dafoe

Calgary, Alberta, Canada
Senior Vice-President, Finance
Senior Vice-President, Finance of ARC

ResourcesJay Billesberger

Calgary, Alberta, Canada
Vice-President, Information

Technology
Vice President, Information Technology of

ARC ResourcesNeil Groeneveld

Calgary, Alberta, Canada
Vice-President, Geosciences and

Exploration
Vice-President, Geosciences and

Exploration of ARC ResourcesWayne Lentz(5)

Calgary, Alberta, Canada
Vice-President, Strategic Planning
Vice-President, Strategic  Planning of ARC

ResourcesAl Roberts

Calgary, Alberta, Canada
Vice-President, Production
Vice-President, Production of ARC

ResourcesAllan R. Twa

Calgary, Alberta, Canada
Secretary
Partner, Burnet, Duckworth & Palmer LLP

(barristers and solicitors)
  Notes:
 (1)
On January 1, 2013, Mr. Dielwart retired as Chief Executive Officer.
 (2)
On January 1, 2013, Mr. Stadnyk was promoted from President and Chief Operating Officer to President and Chief Executive Officer and was appointed as a director.
 (3)
On January 1, 2013, Mr. Kramer was promoted from Senior Vice-President, Operations to Senior Vice-President and Chief Operating Officer.
 (4)
On January 1, 2013, Mr. Anderson was promoted from Senior Vice-President, Engineering to Senior Vice-President, Engineering and Land.
 (5)
On January 1, 2013, Mr. Lentz was promoted from Vice-President, Strategic Planning to Vice-President, Strategy and Business Development.
  2012 Annual Information Form – ARC Resources Ltd.
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  Table of Contents
 
 Membership of Board Committees
  The following chart sets out the membership of the committees of the Board of Directors as at December 31, 2012.
  Name of Director
Audit
Reserves
Risk
Human

Resources & Compensation
Policy

& Board

Governance
Health,

Safety &

EnvironmentNon-Independent DirectorsJohn P. DielwartIndependent DirectorsMac H. Van Wielingen


√
√
√Walter DeBoni
√
√



ChairFred J. Dyment
√
√
ChairTimothy J. Hearn



Chair
√
√James C. Houck
√
Chair



√Harold N. Kvisle


√

√Kathleen M. O'Neill
Chair


√Herbert C. Pinder, Jr.

√

√
Chair
  All committees are comprised of independent directors.  Mr. Dielwart retired from the position of CEO of ARC Resources effective January 1, 2013 but remains as a director and will be considered to be a non-independent director for a period of three years from his retirement.  Mr. Stadnyk was promoted to the position of President and CEO of ARC Resources effective January 1, 2013 and was appointed as a director on such date.  Mr. Stadnyk will be considered to be a non-independent director.
  With the exception of the following individuals, the officers and directors have held the position set forth as their principal occupation for the last five years.
  —
Prior to January 1, 2013, John P. Dielwart was Chief Executive Officer of ARC Resources and prior to February 2009 was President and Chief Executive Officer of ARC Resources.
  —
Prior to April 2008, Timothy Hearn was Chief Executive Officer and Chairman of Imperial Oil Limited.
  —
Prior to August 2012, James Houck was President and Chief Executive Officer of The Churchill Corporation.
  —
Prior to September 2012, Harold N. Kvisle was an independent businessman and prior to July 2010, he was President and Chief Executive Officer of TransCanada Corporation and TransCanada Pipelines Ltd.
  —
Prior to January 1, 2013, Myron M. Stadnyk was President and Chief Operating Officer of ARC Resources and prior to February 2009 was Senior Vice-President and Chief Operating Officer of ARC Resources.
  —
Prior to January 1, 2013, Cameron S. Kramer was Senior Vice-President, Operations of ARC Resources and prior to September 2011 was Senior Vice-President, North American Operations of Canadian Natural Resources Limited.
  —
Prior to January 1, 2013, Terry M. Anderson was Senior Vice-President, Engineering of ARC Resources; prior to July 2011 was Vice-President, Engineering of ARC Resources; and prior to May 2010, was Vice-President, Operations of ARC Resources.
  —
Prior to July 2011, P. Van R. Dafoe was Vice-President, Finance of ARC Resources, prior to March 2010, was Vice-President and Treasurer of ARC Resources.
  —
Prior to July 2011, Jay Billesberger was Manager, Information Technology of ARC Resources.
  2012 Annual Information Form – ARC Resources Ltd.
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  —
Prior to July 2012, Neil Groeneveld was Vice-President, Geosciences of ARC Resources and prior to July 2008, was Manager, Geology of ARC Resources.
 
 —
Prior to January 1, 2013, Wayne Lentz was Vice President, Strategic Planning of ARC Resources and prior to July 2011 was Manager, Strategic Planning of ARC Resources.
 
 —
Prior to September 2011, Al Roberts was Vice-President, Operations of ARC Resources and prior to May 2010, was Manager, Southern Operations of ARC Resources.
 Officer Biographies
  The following comprises a brief description of the background of the officers of ARC Resources:
  Myron M. Stadnyk, P.Eng.
  Mr. Stadnyk is currently President and Chief Executive Officer of ARC Resources and has overall management responsibility for ARC Resources.  Mr. Stadnyk joined ARC in 1997 as the Company's first operations employee and in 2005 was appointed Senior Vice-President, Operations and Chief Operating Officer.  From 2009 to January 1, 2013, he held the position of President and Chief Operating Officer.  Prior to joining ARC, Mr. Stadnyk worked with a major oil and gas company in both domestic and international operations.  He holds a Bachelor of Science in Mechanical Engineering from the University of Saskatchewan and is a graduate of the Harvard Business School Advanced Management program.  Mr. Stadnyk joined ARC's Board of Directors in 2013.  He is a member of the Association of Professional Engineers and Geoscientists of Alberta, Saskatchewan, Manitoba and British Columbia and currently serves as a governor for the Canadian Association of Petroleum Producers.
  Steven W. Sinclair, B. Comm., CA
  Mr. Sinclair is Senior Vice-President and Chief Financial Officer of ARC Resources and oversees the finance, treasury, accounting, tax and marketing teams at ARC.  Mr. Sinclair joined ARC in 1996 and has over 30 years of experience in the oil and gas industry.  He holds a Bachelor of Commerce from the University of Calgary, and a Chartered Accountant's designation which he received in 1981.  Mr. Sinclair is a member of the Alberta and Canadian Institutes of Chartered Accountants.
  Cameron S. Kramer, P. Eng.
  Mr. Kramer is currently Senior Vice-President and Chief Operating Officer of ARC Resources and is responsible for execution of all aspects of ARC's operations and capital program.  He has over 22 years of experience in the North American oil and gas industry.  Prior to joining ARC in 2011, Mr. Kramer worked with a major oil and gas company as Senior Vice-President, North American Operations.  Mr. Kramer brings a broad background in operations and leadership.  He holds a Bachelor of Science in Chemical and Petroleum Engineering from the University of Calgary and is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).
  David P. Carey, P.Eng., MBA
  Mr. Carey is Senior Vice-President, Capital Markets of ARC Resources and is responsible for all facets of investor relations and corporate governance.  Mr. Carey brings over 30 years of diverse experience in the Canadian and International energy industries covering exploration, production and project evaluations.  Prior to joining ARC in 2001, Mr. Carey held senior positions with Athabasca Oil Sands Trust and a major Canadian oil and gas company.  He holds both a Bachelor of Science in Geological Engineering and a Master in Business Administration from Queen's University.  Mr. Carey is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).
  Terry Gill, B.PE.
  Mr. Gill is Senior Vice-President, Corporate Services of ARC Resources and oversees all human resources, information technology and legal services related activities.  Prior to joining ARC in 2007, Mr. Gill spent eight years with a major national distribution company as a senior executive.  He also has spent 15 years in the oil and gas industry and has broad experience in all areas of talent management.  Mr. Gill holds a Bachelor of Physical Education in Coaching Leadership from the University of Alberta and has coached high performance athletes at an elite level.
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  Terry M. Anderson, P.Eng.
  Mr. Anderson is currently Senior Vice-President, Engineering and Land of ARC Resources and is responsible for all of ARC's engineering, joint ventures and mineral land related activities.  He has over 20 years of experience in operations and engineering.  Prior to joining ARC in 2000, he worked at a major oil and gas company.  Mr. Anderson holds a Bachelor of Science in Petroleum Engineering from the University of Wyoming.  He is a member of the Association of Professional Engineers and Geoscientists of Alberta, Saskatchewan and British Columbia.
  P. Van R. Dafoe, B. Comm., CMA
  Mr. Dafoe is Senior Vice-President, Finance of ARC Resources and is responsible for all of ARC's financial risk management, marketing, tax and treasury related activities.  Mr. Dafoe joined ARC in 1999, after 13 years with various companies in the finance and accounting areas of the oil and gas industry.  He has a Bachelor of Commerce (Honours) from the University of Manitoba and obtained his Certified Management Accountant's designation in 1995.
  Jay Billesberger, B.Sc.
  Mr. Billesberger is Vice-President, Information Technology of ARC Resources and is responsible for all information technology related activities.  Mr. Billesberger has over 14 years of experience in information technology.  Prior to joining ARC in 2000, he worked with various oil and gas and mid-stream companies.  He has a Bachelor of Science in Computer Information Systems from DeVry Institute of Technology.
  Neil Groeneveld, P. Geol.
  Mr. Groeneveld is currently Vice-President, Geosciences and Exploration of ARC Resources and is responsible for the execution of ARC's geophysical and geological activities.  He has over 20 years of experience in the western Canadian oil and gas industry and brings a broad background in oil and gas development, exploration and operations.  Prior to joining ARC in 2003, Mr. Groeneveld held senior positions with large and intermediate oil and gas companies.  He holds a Masters of Science in Geology from the University of Regina.  Mr. Groeneveld is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).
  Wayne Lentz, P.Eng.
  Mr. Lentz is currently Vice-President, Strategy and Business Development of ARC Resources and is responsible for strategic planning and related activities.  He brings over 25 years of experience in the oil and gas business covering production, engineering and operations.  Prior to joining ARC in 1999, Mr. Lentz worked with a major E&P company in both domestic and international operations.  He holds a Bachelor of Science in Petroleum Engineering from the University of Alberta.  Mr. Lentz is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA).
  Al Roberts
  Mr. Roberts is Vice-President, Production of ARC Resources and manages all aspects of field production operations and health, safety and environment.  He has over 30 years of broad experience across the western Canadian sedimentary basin in production operations, completions and facilities construction.  Prior to joining ARC in 1997, Mr. Roberts spent 18 years managing field operations for both junior and intermediate producers.
  Allan R. Twa, Q.C.
  Mr. Twa acts as Corporate Secretary of ARC Resources.  A member of the Alberta Bar since 1971, Mr. Twa is a partner in the law firm Burnet, Duckworth & Palmer LLP.  Mr. Twa holds a B.A. (Political Science) from the University of Calgary, a LL.B. from the University of Alberta and a LL.M. from the University of London, England.  Over the last 35 years, Mr. Twa has been engaged in a legal practice involving legal administration of public companies and trusts, corporate finance, and mergers and acquisitions.
  All of the current directors of ARC Resources other than Myron M. Stadnyk were elected as directors of ARC Resources Ltd. on May 15, 2012 to hold office until the next annual meeting of ARC Resources, which is scheduled to be held on May 15, 2013.  Mr. Stadnyk was appointed as a director of ARC Resources on January 1, 2013.  As at December 31, 2012, the directors and officers of ARC Resources, as a group, beneficially owned, or controlled or directed, directly or indirectly, 2,264,523 Common Shares or approximately 0.7 per cent of the outstanding Common Shares.
  2012 Annual Information Form – ARC Resources Ltd.
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  AUDIT COMMITTEE DISCLOSURES
  Multilateral Instrument 52-110 ("MI 52-110") relating to audit committees has mandated certain disclosures for inclusion in this Annual Information Form.  The text of the Audit Committee's mandate is attached as Appendix C to this Annual Information Form and such mandate reflects a number of amendments which were made subsequent to year-end.
  Members of the Audit Committee
  As of December 31, 2012, the members of the Audit Committee were Kathleen O'Neill (Chair), Walter DeBoni, Fred J. Dyment and James C. Houck; each is independent and financially literate within the meaning of MI 52-110.  The following comprises a brief summary of each member's education and experience:
  Kathleen M. O'Neill
  Ms. O'Neill is a Corporate Director and has extensive experience in accounting and financial services.  Previously, she was an Executive Vice-President of Bank of Montreal Financial Group with accountability for a number of major business units.  Prior to joining the Bank of Montreal Financial Group in 1994, she was a partner with PricewaterhouseCoopers.  Ms. O'Neill is an FCA (Fellow of the Institute of Chartered Accountants) and has an ICD.D designation from the Institute of Corporate Directors.  She currently serves on the board of directors and as Chair of the audit committee of Finning International Inc., the world’s largest Caterpillar dealer, and serves on the board of directors of Invesco Canada Funds.  Ms. O'Neill is on the board of the University of St. Michael’s College, University of Toronto and is past Chair of St. Joseph's Health Centre, Toronto.  She also is on the Steering Committee on Enhancing Audit Quality sponsored by the Canadian Institute of Chartered Accountants and the Canadian Public Accountability Board. Ms. O'Neill has been a director of ARC since 2009.
  Walter DeBoni
  Mr. DeBoni is a Corporate Director and has extensive experience in the oil and gas industry.  Mr. DeBoni retired from Husky Energy Inc. in 2005, where he held the position of Vice-President, Canada Frontier and International Business.  Prior thereto, he was the Chief Executive Officer of Bow Valley Energy.  In addition to his time at Husky and Bow Valley he has held numerous top executive posts in the oil and gas industry with major corporations.  Mr. DeBoni holds a Bachelor of Science in Chemical Engineering from the University of British Columbia and a Masters in Business Administration with a major in Finance from the University of Calgary.  He is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and the Society of Petroleum Engineers.  He currently serves on the board of directors for Sterling Resources Ltd.  Mr. DeBoni is a past Chairman of the Petroleum Society of CIM and a past Director of the Society of Petroleum Engineers.  Mr. DeBoni has been a director of ARC Resources since 1996.
  Fred J. Dyment
  Mr. Dyment has over 30 years of extensive experience in the oil and gas industry and is currently an independent businessman.  He has held positions as President and Chief Executive Officer for Maxx Petroleum and President and Chief Executive Officer of Ranger Oil Limited.  Mr. Dyment received a Chartered Accountant designation from the province of Ontario in 1972.  Currently, he serves on the board of directors for Tesco Corporation, Transglobe Energy Corporation, Major Drilling Group International and WesternZagros Resources Ltd.  Mr. Dyment has been a director of ARC since 2003.
  James C. Houck
  Mr. Houck has over  30 years of diversified experience in the oil and gas industry.  Most recently, he held the position of President and Chief Executive Officer of The Churchill Corporation, a construction and industrial services company.  Prior thereto, he was President and Chief Executive Officer of Western Oil Sands.  The greater part of his career was spent with ChevronTexaco Inc., where he held a number of senior management and officer positions, including President, Worldwide Power and Gasification Inc., and Vice-President and General Manager, Alternate Energy Department.  Earlier in his career, Mr. Houck held various positions of increasing responsibility in Texaco's conventional oil and gas operations.  Mr. Houck has a Bachelor of Engineering Science degree from Trinity University in San Antonio and a Masters in Business Administration degree from the University of Houston.  Currently, he serves on the board of directors for WesternZagros Resources Ltd.  Mr. Houck has been a director of ARC since 2008.
  2012 Annual Information Form – ARC Resources Ltd.
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  Principal Accountant Fees and Services
  The Audit Committee has not adopted specific policies and procedures for the engagement of non-audit services and pre-approves each such engagement or type of engagement for every fiscal year.
  Our external auditor is Deloitte LLP.  The following is a summary of the external audit services fees by category.
  Summary of External Audit Service Fees

2012


2011Audit Fees

$
864,318


$
982,478Audit Related Fees(1)

$
69,291


$
69,892Tax Fees(2)

$
0


$
0All Other Fees(3)

$
16,329


$
16,241
  Notes:
 (1)
The aggregate fees billed by our external auditor for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements but which are not included in audit services fees.
 (2)
The aggregate fees billed by our external auditor for professional services for municipal property tax compliance, tax advice and tax planning.
 (3)
The assessment fee billed by The Canadian Public Accountability Board per the NI 52-108 mandate for reporting issuers to have an audit completed by a CPAB participant firm.
  CONFLICTS OF INTEREST
  The Board of Directors has adopted a Code of Business Conduct and Ethics and a Code of Ethics for Senior Financial Officers (the "Codes").  In general, the private investment activities of employees, directors and officers are not prohibited, however, should an existing investment pose a potential conflict of interest, the potential conflict is required by the Codes to be disclosed to the Chief Executive Officer, President or the Board of Directors.  Any other activities of employees which pose a potential conflict of interest are also required by the Codes to be disclosed to the Chief Executive Officer, President or the Board of Directors.  Any such potential conflicts of interests will be dealt with openly with full disclosure of the nature and extent of the potential conflicts of interests with the Corporation.
  It is acknowledged in the Codes that employees, officers and directors may be directors or officers of other entities engaged in the oil and gas business, and that such entities may compete directly or indirectly with the Corporation.  No assurance can be given that opportunities identified by directors of ARC Resources will be provided to us.  Passive investments in public or private entities of less than one per cent of the outstanding shares will not be viewed as "competing" with the Corporation.  Any director, officer or employee of ARC Resources which is a director or officer of any entity engaged in the oil and gas business shall disclose such occurrence to the Board of Directors.  Any director, officer or employee of ARC Resources who is actively engaged in the management of, or who owns an investment of one per cent or more of the outstanding shares, in public or private entities shall disclose such holding to the Board of Directors.  In the event that any circumstance should arise as a result of such positions or investments being held or otherwise which in the opinion of the Board of Directors constitutes a conflict of interest which reasonably affects such person's ability to act with a view to the best interests of the Corporation, the Board of Directors will take such actions as are reasonably required to resolve such matters with a view to the best interests of the Corporation.  Such actions, without limitation, may include excluding such directors, officers or employees from certain information or activities of the Corporation.
  The Business Corporations Act (Alberta) provides that in the event that an officer or director is a party to, or is a director or an officer of or has a material interest in any person who is a party to, a material contract or material transaction or proposed material contract or proposed material transaction, such officer or director shall disclose the nature and extent of his or her interest and shall refrain from voting to approve such contract or transaction.
  INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
  There is no material interest, direct or indirect, of any director or senior officer, or to our knowledge any person or company that is the direct or beneficial owner, or who exercises control or direction over more than 10 per cent of outstanding Common Shares, or any associate or affiliate of any of the foregoing, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to affect the Corporation.
  2012 Annual Information Form – ARC Resources Ltd.
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 Table of Contents
  DIVIDENDS AND DISTRIBUTIONS
  Dividend Policy
  In conjunction with the completion of the Trust Conversion, the Board of Directors of ARC Resources established a dividend policy of paying monthly dividends to holders of Common Shares, initially set at $0.10 per Common Share, which will be paid to Shareholders of record on or about the 15th day of each month.  In general, the Board of Directors attempts to set the dividend amount at a level which at that time appears sustainable for a minimum period of six months.  The payment of dividends by the Corporation commenced with a dividend declared to Shareholders of record on January 31, 2011 in the amount of $0.10 per Common Shares made payable on February 15, 2011.
  It is expected that the dividends declared and paid will be "eligible dividends" for the purposes of the Tax Act,  and thus qualify for the enhanced gross-up and tax credit regime available to certain holders of Common Shares.  However, no assurances can be given that all dividends will be designated as "eligible dividends" or qualify as "eligible dividends".
  Notwithstanding the foregoing, the amount of future cash dividends, if any, will be subject to the discretion of the Board of Directors of ARC Resources and may vary depending on a variety of factors and conditions existing from time-to-time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of solvency tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends.
  For information relating to risks relating to dividends, see "Risk Factors - Risk Relating to Our Business and Operations– The Board of ARC Resources has discretion in the payment of dividends and may not chose to maintain the payment of dividends in certain circumstances".
  In certain circumstances, the payment of dividends may be restricted by our borrowing agreements.  For more information see "Other Information Relating to Our Business – Borrowing".
  Dividend History
  The following per Common Share dividends (Trust Unit distributions prior to the completion of the Trust Conversion) were made in the last three completed financial years of ARC:
  Dividends

2012


2011


2010January

$
0.10


$
0.10


$
0.10February

$
0.10


$
0.10


$
0.10March

$
0.10


$
0.10


$
0.10April

$
0.10


$
0.10


$
0.10May

$
0.10


$
0.10


$
0.10June

$
0.10


$
0.10


$
0.10July

$
0.10


$
0.10


$
0.10August

$
0.10


$
0.10


$
0.10September

$
0.10


$
0.10


$
0.10October

$
0.10


$
0.10


$
0.10November

$
0.10


$
0.10


$
0.10December

$
0.10


$
0.10


$
0.10Total

$
1.20


$
1.20


$
1.20
 
 MARKET FOR SECURITIES
  The Common Shares commenced trading on the TSX on January 6, 2011 following the completion of the Trust Conversion.  The trading symbol for the Common Shares is ARX.
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  The following table sets forth the high and low closing prices and the aggregate volume of trading of the Common Shares on the TSX for the periods indicated (as quoted by the TSX):
  Toronto Stock Exchange

2012 Period
High

$
Low

$
VolumeJanuary
$25.52
$22.74
22,250,446February
$25.68
$23.60
14,284,251March
$25.09
$22.90
19,194,559April
$23.00
$18.50
27,035,438May
$21.79
$19.50
20,019,685June
$22.90
$19.51
23,343,479July
$25.66
$21.70
17,272,009August
$24.20
$23.09
18,834,415September
$24.32
$22.75
17,295,777October
$25.01
$23.65
14,756,449November
$24.88
$23.00
14,655,064December
$24.75
$23.56
15,293,467
 
 INDUSTRY CONDITIONS
  Companies operating in the oil and natural gas industry are subject to extensive regulation and control of operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government and with respect to the pricing and taxation of oil and natural gas through agreements among the governments of Canada, Alberta, British Columbia, Saskatchewan and Manitoba, all of which should be carefully considered by investors in the oil and gas industry.  It is not expected that any of these regulations or controls will affect the Corporation's operations in a manner materially different than they will affect other oil and natural gas companies of similar size.  All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments may be enacted.  Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in western Canada.
  Pricing and Marketing
  Oil
  The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil.  Worldwide supply and demand primarily determines oil prices.  The specific price depends in part on oil quality, prices of competing fuels, distance to market, the availability of transportation, value of refined products, the supply/demand balance and contractual terms of sale.  Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB").  Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB. The NEB is currently undergoing a consultation process to update the current regulations governing the issuance of export licences. The updating process is necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act which received Royal Assent on June 29, 2012 (the "Prosperity Act").  In this transitory period, the NEB has issued, and is currently following an "Interim Memorandum of Guidance concerning Oil and Gas Export Applications and Gas Import Applications under Part VI of the National Energy Board Act".
  Natural Gas
  Alberta's natural gas market has been deregulated since 1985.  Supply and demand determine the price of natural gas  and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system such as the Alberta "NIT" (Nova Inventory Transfer), at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer.  Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short-term contracts and the specific point of sale).  As natural gas is also traded on trading platforms such as the Natural Gas Exchange (NGX) or the New York Mercantile Exchange (NYMEX) in the United States, spot and future prices can be set by such supply and demand. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada.  Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada.  Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an NEB order.  Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB.
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  The North American Free Trade Agreement
  The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico became effective on January 1, 1994.  In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not:  (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply.
  All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited.  The signatory countries are also prohibited from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings.  NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports.  NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes.
  Royalties and Incentives
 
 General
  In addition to federal regulation, each province has legislation and regulations which govern royalties, production rates and other matters.  The royalty regime in a given province is a significant factor in the profitability of oil sands projects, crude oil, natural gas liquids, sulphur and natural gas production.  Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties.  Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production.  The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced.  Other royalties and royalty-like interests are carved out of the working interest owner's interest, and from time to time,  through non-public transactions.  These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.
  Occasionally the governments of the western Canadian provinces create incentive programs, often during periods of low commodity prices.  Such programs can provide royalty rate reductions, royalty holidays or royalty tax credits to encourage exploration and development activity.
  Alberta
  Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.
  Royalties are currently paid pursuant to "The New Royalty Framework" (implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008) and the "Alberta Royalty Framework", which was implemented in 2010.
  Royalty rates for conventional oil are set by a single sliding rate formula, which is applied monthly and incorporates separate variables to account for production rates and market prices.  Effective January 1, 2011, the maximum royalty payable under the royalty regime was set at 40 per cent.  The royalty curve for conventional oil amends the price component of the conventional oil royalty formula to moderate the increase in the royalty rate at prices higher than $535/m3.
  Royalty rates for natural gas under the royalty regime are similarly determined using a single sliding rate formula incorporating separate variables to account for production rates and market prices.  Effective January 1, 2011, the maximum royalty payable under the royalty regime was set at 36 per cent.  The royalty curve amends the price component of the natural gas royalty formula to moderate the increase in the royalty rate at prices higher than $5.00/GJ.
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   Producers of oil and natural gas from freehold lands in Alberta are required to pay annual freehold mineral rights taxes.  The level of the freehold mineral rights tax is based on the volume of monthly production and a specified rate of tax for both oil and gas.
  The Government of Alberta currently has in place two royalty programs, both of which commenced in 2008 with the intention to encourage the development of deeper, higher cost oil and gas reserves.  A five year program for conventional oil exploration wells over 2,000 metres provides qualifying wells with up to a $1 million or 12 months of royalty relief, whichever comes first, and a five year program for natural gas wells deeper than 2,000 metres provides a sliding scale royalty credit based on depth of up to $3,750 per metre.
  On November 19, 2008, the Government of Alberta introduced a five year program of transitional royalty rates with the intent of promoting new drilling.  Under this program, companies drilling new natural gas or conventional deep oil wells between 1,000 and 3,500 metres receive a one-time option, on a well-by-well basis, to adopt either the transitional royalty rates or those outlined in the royalty regime.  The option to elect the transitional royalty rates expired on February 15, 2011 and on January 1, 2014, all producers operating under the transitional royalty rates will automatically become subject to the royalty regime.
  On March 17, 2011, the Government of Alberta approved the New Well Royalty Regulation which provides for a maximum five per cent royalty rate for eligible new wells for the first 12 productive months or until the regulated "volume cap" is reached. This regulation is set to expire June 30, 2018.
  In addition to the foregoing, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources (the "Emerging Resource and Technologies Initiative").  Specifically:
  —
Coalbed methane wells will receive a maximum royalty rate of five per cent for 36 producing months on up to 750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;
  —
Shale gas wells will receive a maximum royalty rate of five per cent for 36 producing months with no limitation on production volume, retroactive to wells that began producing on or after May 1, 2010;
  —
Horizontalgaswells will receive a maximum royalty rate of five per cent for 18 producing months on up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010; and
  —
Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty rate of five per cent with volume and production month limits set according to the depth of the well (including the horizontal distance), retroactive to wells that commenced drilling on or after May 1, 2010.
 
 The Emerging Resource and Technologies Initiative will be reviewed in 2014, and the Government of Alberta has committed to providing industry with three years notice at that time if it decides to discontinue the program.
  The Innovative Energy Technologies Program (the "IETP"), which is currently in place, has the stated objectives of increasing recovery from oil and gas deposits, finding technical solutions to the gas over bitumen issue, improving the recovery of bitumen by in-situ and mining techniques and improving the recovery of natural gas from coal seams.  The IETP provides royalty adjustments to specific pilot and demonstration projects that utilize new or innovative technologies to increase recovery from existing reserves.
  British Columbia
  Producers of oil and natural gas from Crown lands in British Columbia are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.  The amount payable as a royalty in respect of oil depends on the type and vintage of the oil, the quantity of oil produced in a month and the value of that oil.  Generally, oil is classified as either light or heavy and the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 ("old oil"), between October 31, 1975 and June 1, 1998 ("new oil"), or after June 1, 1998 or through an Enhanced Oil Recovery ("EOR") Scheme ("third tier oil").  The royalty calculation takes into account the production of oil on a well-by-well basis, the specified royalty rate for a given vintage of oil, the average unit selling price of the oil and any applicable royalty exemptions.  Royalty rates are reduced on low productivity wells, reflecting the higher unit costs of extraction, and are the lowest for third tier oil, reflecting the higher unit costs of both exploration and extraction.
  The royalty payable in respect of natural gas produced on Crown lands is determined by a sliding scale formula based on a reference price, which is the greater of the average net price obtained by the producer and a prescribed
 
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  minimum price.  For non-conservation gas (not produced in association with oil), the royalty rate depends on the date of acquisition of the oil and natural gas tenure rights and the spud date of the well and may also be impacted by the select price, a parameter used in the royalty rate formula to account for inflation.  Royalty rates are fixed for certain classes of non-conservation gas when the reference price is below the select price.  Conservation gas is subject to a lower royalty rate than non-conservation gas.  Royalties on natural gas liquids are levied at a flat rate of 20 per cent of the sales volume.
  Producers of oil and natural gas from freehold lands in British Columbia are required to pay monthly freehold production taxes.  For oil, the level of the freehold production tax is based on the volume of monthly production.  It is either a flat rate, or, at certain production levels, is determined using a sliding scale formula based on the reference price similar to that applied to oil production on Crown land.  For natural gas, the freehold production tax is either a flat rate, or, at certain production levels, is determined using a sliding scale formula based on the reference price similar to that applied to natural gas production on Crown land, and depends on whether the natural gas is conservation gas or non-conservation gas.  The freehold production tax rate for natural gas liquids is a flat 12.25 per cent.
  British Columbia maintains a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbia's natural gas low productivity wells.  These include both royalty credit and royalty reduction programs, including the following:
  —
Summer Royalty Credit Program providing a royalty credit equal to 10 per cent of the goods and services costs up to $100,000 for wells drilled between April 1 and November 30 of each year; effective immediately, this program will be discontinued; any qualifying wells that were drilled between April 1, 2012 and up to and including November 30, 2012 will still be eligible to apply for and receive the credit if the application is submitted on or before June 30, 2013.
  —
Deep Royalty Credit Program providing a royalty credit defined in terms of a dollar amount applied against royalties, is well specific and applies to drilling and completion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal wells with a true vertical depth greater than 2,300 metres (or 1,900 metres if spud after August 1, 2009) and if certain other criteria are met and is intended to reflect the higher drilling and completion costs that relate to location specific factors; effective April 1, 2013, there is a minimum royalty of three per cent for all natural gas wells that qualify for this program.
  —
Deep Re-Entry Royalty Credit Program providing royalty credit for deep re-entry wells with a true vertical depth to the top of pay of the re-entry well event that is greater than 2,300 metres and a re-entry date subsequent to December 1, 2003; or if the well was spud on or after January 1, 2009, with a true vertical depth to the completion point of the re-entry well event being greater than 2,300 metres;
  —
Deep Discovery Royalty Credit Program providing the lesser of a three year royalty holiday or 283,000,000 m3 of royalty free gas for deep discovery wells with a true vertical depth greater than 4,000 metres whose surface locations are at least 20 kilometres away from the surface location of any well drilled into a recognized pool within the same formation;
  —
Natural Gas Royalty Reduction providing a reduced royalty on wells drilled on land rights acquired after June 1, 1998 and completed within five  years of the date the rights are issued;
  —
Coalbed Gas Royalty Reduction and Credit Program providing a royalty reduction for coalbed gas wells with average daily production less than 17,000 m3 as well as a royalty credit for coalbed gas wells equal to $50,000 for wells drilled on Crown land and a tax credit equal to $30,000 for wells drilled on freehold land;
  —
Marginal Royalty Reduction Program providing monthly royalty reductions for low productivity non-conservation natural gas wells with average monthly production under 25,000 m3 during the first 12 production months and average daily production less than 23 m3 for every metre of marginal well depth;
  —
Ultra-Marginal Royalty Reduction Program providing additional royalty reductions for low productivity shallow non-conservation natural gas wells with a true vertical depth of less than 2,500 metres in the case of vertical wells, and a total vertical depth of less than 2,300 metres in the case of a horizontal well, average monthly production under 60,000 m3 during the first 12 production months and average daily production less than 11m3 (development wells) or 17 m3 (exploratory wildcat wells) for every 100 metres of marginal well depth; and
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   —
Net Profit Royalty Reduction Program providing reduced initial royalty rates to facilitate the development and commercialization of technically complex resources such as coalbed gas, tight gas, shale gas and enhanced-recovery projects, with higher royalty rates applied once capital costs have been recovered.
 Oil produced from an oil well that is located on either Crown or freehold land and completed in a new pool discovered subsequent to June 30, 1974 may also be exempt from the payment of a royalty for the first 36 months of production or 11,450 m3 of production, whichever comes first.
  The Government of British Columbia also maintains an Infrastructure Royalty Credit Program (the "Infrastructure Royalty Credit Program") which provides royalty credits for up to 50 per cent of the cost of certain approved road construction or pipeline infrastructure projects intended to facilitate increased oil and gas exploration and production in under-developed areas and to extend the drilling season.
  In August 2012, the Government of British Columbia announced that it is bringing in a nominal two per cent royalty on both oil and natural gas on the revenue for the first year of production for wells drilled from September 2012 through to June 2013.
  Saskatchewan
  In Saskatchewan, the amount payable as Crown royalty or freehold production tax in respect of oil depends on the type and vintage of oil, the quantity of oil produced in a month, the value of the oil produced and specified adjustment factors determined monthly by the provincial government.  For Crown royalty and freehold production tax purposes, conventional oil is divided into "types", being "heavy oil", "southwest designated oil" or "non-heavy oil other than southwest designated oil".  The conventional royalty and production tax classifications ("fourth tier oil", "third tier oil", "new oil" and "old oil") depend on the finished drilling date of a well and are applied to each of the three crude oil types slightly differently.  Heavy oil is classified as third tier oil (having a finished drilling date on or after January 1, 1994 and before October 1, 2004), fourth tier oil (having a finished drilling date on or after October 1, 2002 or incremental oil from new or expanded waterflood projects) or new oil (oil from wells drilled on or after January 1, 1994).  Southwest designated oil uses the same definitions of third and fourth tier oil but new oil is defined as conventional oil produced from a horizontal well having a finished drilling date on or after February 9, 1998 and before October 1, 2002.  For non-heavy oil other than southwest designated oil, the same classification is used but new oil is defined as conventional oil produced from a vertical well completed after 1973 and having a finished drilling date prior to 1994, whereas old oil is defined as conventional oil not classified as third or fourth tier oil or new oil.  Production tax rates for freehold production are determined by first determining the Crown royalty rate and then subtracting the "Production Tax Factor" ("PTF") applicable to that classification of oil.  Currently the PTF is 6.9 for "old oil", 10.0 for "new oil" and "third tier oil" and 12.5 for "fourth tier oil".  The minimum rate for freehold production tax is zero.
  Base prices are used to establish lower limits in the price-sensitive royalty structure for conventional oil and apply at a reference well production rate of 100 m3 for "old oil", "new oil" and "third tier oil", and 250 m3 per month for "fourth tier oil".  Where average wellhead prices are below the established base prices of $100 per m3 for third and fourth tier oil and $50 per m3 for new oil and old oil, base royalty rates are applied.  Base royalty rates are 5 per cent for all fourth tier oil, 10 per cent for heavy oil that is third tier oil or new oil, 12.5 per cent for southwest designated oil that is third tier oil or new oil, 15 per cent for non-heavy oil other than southwest designated oil that is third tier or new oil, and 20 per cent for old oil.  Where average wellhead prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base oil price.  Marginal royalty rates are 30 per cent for all fourth tier oil, 25 per cent for heavy oil that is third tier oil or new oil, 35 per cent for southwest designated oil that is third tier oil or new oil, 35 per cent for non-heavy oil other than southwest designated oil that is third tier or new oil, and 45 per cent for old oil.
  The amount payable as Crown royalty or freehold production tax in respect of natural gas production is determined by a sliding scale based on the actual price received, the quantity produced in a given month, the type of natural gas, and the classification of the natural gas.  Like conventional oil, natural gas may be classified as "non-associated gas" (gas produced from gas wells) or "associated gas" (gas produced from oil wells) and royalty rates are determined according to the finished drilling date of the respective well.  Non-associated gas is classified as new gas (having a finished drilling date before February 9, 1998 with a first production date on or after October 1, 1976), third tier gas (having a finished drilling date on or after February 9, 1998 and before October 1, 2002), fourth tier gas (having a finished drilling date on or after October 1, 2002) and old gas (not classified as either third tier, fourth tier or new gas).  A similar classification is used for associated gas except that the classification of old gas is not used, the definition of fourth tier gas also includes production from oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of more than 3,500 m3 of gas for every m3 of oil, and new gas is defined as oil produced from a well with a finished drilling date before February 9, 1998 that received special approval, prior to October 1, 2002, to produce oil and gas concurrently without gas-oil ratio penalties.  Natural
 
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 gas liquids and by-products recovered at gas processing plants are not subject to a royalty.  Gas liquids which are produced and measured at the wellhead are treated as crude oil for royalty purposes.
  On December 9, 2010, the Government of Saskatchewan enacted the Freehold Oil and Gas Production Tax Act, 2010with the intention to facilitate the efficient payment of freehold production taxes by industry.  Two new regulations with respect to this legislation are:  (i) The Freehold Oil and Gas Production Tax Regulations, 2012 which sets out the terms and conditions under which the taxes are calculated and paid; and (ii) The Recovered Crude Oil Tax Regulations, 2012 which sets out the terms and conditions under which taxes on recovered crude oil that was delivered from a crude oil recovery facility on or after March 1, 2012 are to be calculated and paid.
  As with conventional oil production, base prices based on a well reference rate of 250 per thousand m3/month are used to establish lower limits in the price-sensitive royalty structure for natural gas.  Where average field-gate prices are below the established base prices of $50 per thousand m3 for third and fourth tier gas and $35 per thousand m3 for new gas and old gas, base royalty rates are applied.  Base royalty rates are five per cent for all fourth tier gas, 15 per cent for third tier or new gas, and 20 per cent for old gas.  Where average well-head prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base gas price.  Marginal royalty rates are 30 per cent for all fourth tier gas, 35 per cent for third tier and new gas, and 45 per cent for old gas.  The current regulatory scheme provides for certain differences with respect to the administration of "fourth tier gas" which is associated gas.
  The Government of Saskatchewan currently provides a number of targeted incentive programs.  These include both royalty reduction and incentive volume programs, including the following:
  —
Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 per cent) and freehold tax rates (a freehold production tax rate of zero per cent) on incentive volumes of 8,000 m3 for deep development vertical oil wells, 4,000 m3 for non-deep exploratory vertical oil wells and 16,000 m3 for deep exploratory vertical oil wells (more than 1,700 metres or within certain formations) and after the incentive volume is produced, the oil produced will be subject to the "fourth tier" royalty tax rate;
  —
Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 per cent) and freehold tax rates (a freehold production tax rate of zero per cent) on incentive volumes of 25,000,000 m3 for qualifying exploratory gas wells;
  —
Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 per cent) and freehold tax rates on incentive volumes of 6,000 m3 for non-deep horizontal oil wells and 16,000 m3 for deep horizontal oil wells (more than 1,700 metres or within certain formations) and after the incentive volume is produced, the oil produced will be subject to the "fourth tier" royalty tax rate;
  —
Royalty/Tax Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and before April 1, 2013 providing for a classification of the well as a qualifying exploratory gas well and resulting in a reduced Crown royalty (a Crown royalty rate of the lesser of "fourth tier oil" Crown royalty rate and 2.5 per cent and freehold tax rates (a freehold production tax rate of zero per cent) on incentive volumes of 25,000,000 m3 for horizontal gas wells and after the incentive volume is produced, the gas produced will be subject to the "fourth tier" royalty tax rate;
  —
Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 whereby incremental production from approved waterflood projects is treated as fourth tier oil for the purposes of Crown royalty and freehold tax calculations;
  —
Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 providing lower Crown royalty and freehold tax determinations based in part on the profitability of EOR projects during and subsequent to the payout of the EOR operations;
  —
Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing on or after April 1, 2005 providing a Crown royalty of one per cent of gross revenues on enhanced oil recovery projects pre-payout and 20 per cent of EOR operating income post-payout and a freehold production tax of zero per cent pre-payout and eight per cent post-payout on operating income from EOR projects; and
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Royalty/Tax Regime for High Water-Cut Oil Wells designed to extend the product lives and improve the recovery rates of high water-cut oil wells and granting "third tier oil" royalty/tax rates to incremental high water-cut oil production resulting from qualifying investments made to rejuvenate eligible oil wells and/or associated facilities.
 In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the Government of Canada disallowing Crown royalties and similar taxes as a deductible business expense for income tax purposes.  As of January 1, 2007, the remaining balance of any unused RTR is limited in its carry forward to seven years because of the Government of Canada's initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income.
  On June 22, 2011, the Government of Saskatchewan released the Upstream Petroleum Industry Associated Gas Conservation Standards, which are designed to reduce emissions resulting for the flaring and venting of associated gas (the "Associated Natural Gas Standards").  The Associated Natural Gas Standards were jointly developed with industry and the implementation of such standards commenced on July 1, 2012 for new wells and facilities licensed on or after such date. These will apply to existing licensed wells and facilities on July 1, 2015.
  Manitoba
  In Manitoba, the royalty amount payable on oil produced from Crown lands depends on the classification of the oil produced as "old oil" (produced from a well drilled prior to April 1, 1974 that does not qualify as new oil or third tier oil), "new oil" (oil that is not third tier oil and is produced from a well drilled on or after April 1, 1974 and prior to April 1, 1999, from an abandoned well re-entered during that period, from an old oil well as a result of an enhanced recovery project implemented during that period, or from a horizontal well), "third tier oil" (oil produced from a vertical well drilled after April 1, 1999, an abandoned well re-entered after that date, an inactive vertical well activated after that date, a marginal well that has undergone a major workover, or from an old oil well or a new oil well as a result of an enhanced recovery project implemented after that date), or "holiday oil" (oil that is exempt from any royalty or tax payable).  Royalty rates are calculated on a sliding scale and based on the monthly oil production from a spacing unit, or oil production allocated to a unit tract under a unit agreement or unit order from the Minister.  For horizontal wells, the royalty on oil produced from Crown lands is calculated based on the amount of oil production allocated to a spacing unit in accordance with the applicable regulations.
  Royalties payable on natural gas production from Crown lands are equal to 12.5 per cent of the volume of natural gas sold, calculated for each production month.
  Producers of oil and natural gas from freehold lands in Manitoba are required to pay monthly freehold production taxes.  The freehold production tax payable on oil is calculated on a sliding scale based on the monthly production volume and the classification of oil as old oil, new oil, third tier oil and holiday oil.  Producers of natural gas from freehold lands in Manitoba are required to pay a monthly freehold production tax equal to 1.2 per cent of the volume sold, calculated per production month.  There is no freehold production tax payable on gas consumed as lease fuel.
  The Government of Manitoba maintains a Drilling Incentive Program (the "Program") with the intent of promoting investment in the sustainable development of petroleum resources.  The Program provides the licensee of newly drilled wells, or qualifying wells where a major workover has been completed, with a "holiday oil volume" pursuant to which no Crown royalties or freehold production taxes are payable until the holiday oil volume has been produced.  Holiday oil volumes must be produced within 10 years of the finished drilling date or the completion date of a major workover.  Wells drilled for injection, or converted to injection wells, in an approved enhanced recovery project, earn one year holiday for portions of the project area.  Under the Program, wells drilled for purposes of injection (or wells converted to injection prior to producing predetermined volumes of oil) in an approved enhanced oil recovery project earn a one-year holiday for portions of the project area.
  The Program consists of the following components, such components being subject to additional considerations under the Crown Royalty and Incentives Regulation:
  —
New Well Incentive provides licensees of newly drilled, non-horizontal wells drilled prior to January 1, 2014 with a holiday oil volume to a maximum of 10,000 m3;
  —
Deep Drilling Incentive provides licensees who drill a well to a total depth sufficient to penetrate the Devonian Duperow formation with a holiday oil volume of up to 20,000 m3, and licensees who drill a well deeper than the Devonian Three Forks formation can make a one-time assignment of up to 10,000 m3 of holiday oil volume earned through previous drilling or major workovers to such well's holiday oil volume;
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  —
Horizontal Well Initiative provides licensees of horizontal wells drilled prior to January 1, 2014 with a holiday oil volume of 10,000 m3, and the first horizontal leg (unless otherwise approved) drilled from an existing horizontal well on or after January 1, 2009 and prior to January 1, 2014 and more than one year after the finished drilling date of the well), will earn an additional holiday royalty volume of 3,000 m3;
  —
Marginal Well Major Workover Incentive provides licensees of marginal wells where a major workover is completed prior to January 1, 2014 with a holiday oil volume of 500 m3, with a marginal oil well defined as an abandoned well or a well that was either not operated over the previous 12 months or produced oil at an average rate of less than one m3 per operating day; and
  —
Injection Well Incentive provides a one year exemption from the payment of Crown royalties or freehold production taxes on production allocated to a unit tract in which a well is drilled or converted to water injection.
 Further, holiday oil volumes earned by a newly drilled well or a marginal well that has undergone a major workover can be transferred to a Holiday Oil Volume Account at the request of the licensee, the purpose of which is to optimize the value of holiday oil volumes earned by providing a company with the flexibility of allocating holiday oil volumes earned among new wells.
  The Program is set to expire on January 1, 2014.  The Government of Manitoba is currently reviewing its entire royalty structure commencing with an industry consultation.
  Land Tenure
  The respective provincial governments predominantly own crude oil and natural gas located in the western provinces.  Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments.  Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.
  Each of the provinces of Alberta, British Columbia, Saskatchewan and Manitoba has implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license.  On March 29, 2007, British Columbia expanded its policy of deep rights reversion for new leases to provide for the reversion of all  formations that do not contain an identified oil or natural gas pool at the end of their primary term (“zone specific retention”).
  Alberta also has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses.  For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or the intermediate term of the license.  Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice.  Leases and licences granted prior to January 1, 2009, but continued after that date, are not subject to shallow rights reversion until they continue past their primary term (at which time the application of deep rights reversion occurs).  Afterwards, the holders of such agreements will be served with shallow rights reversion notices based on vintage and location similar to leases and licences that were already continued as of January 1, 2009.  The order in which these agreements will receive reversion notices will depend on their vintage and location, and at such time the Alberta Department of Energy has not determined the point in time it will issue reversion notices on agreements issued prior to January 1, 2009.
  Environmental Regulation
  The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, all of which is subject to governmental review and revision from time to time.  Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide.  In addition, such legislation sets out the requirements for the satisfactory abandonment and reclamation of well and facility sites.  Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.
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 On a Federal level and pursuant to the Prosperity Act, the Government of Canada amended or appealed several pieces of federal environmental legislation and in addition, created a new federal environment assessment regime.  The changes to the environmental legislation under the Prosperity Act are intended to provide for more efficient and timely environmental assessments of projects that previously had been subject to overlapping legislative jurisdiction.
  In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF").  The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province.  It calls for the development of region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.
  The Alberta Land Stewardship Act (the "ALSA") was proclaimed in force in Alberta on October 1, 2009 and provides the legislative authority for the Government of Alberta to implement the policies contained in the ALUF.  Regional plans established pursuant to the ALSA will be deemed to be legislative instruments equivalent to regulations and will be binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry.  In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail.  Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan.  The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, approvals and authorizations for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan.  Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.
  On August 22, 2012, the Government of Alberta approved the Lower Athabasca Regional Plan ("LARP") which came into effect on September 1, 2012.  The LARP covers approximately 93,212 square kilometres and is in the northeast corner of Alberta.  The region includes a substantial portion of the Athabasca oil sands area, which contains approximately 82 per cent of the provinces oil sands resource and much of the Cold Lake oil sands area. LARP establishes six new conservation areas, bringing the total conserved land in the region to two million hectares, or 22 per cent—an area three times the size of Banff National Park. The Alberta government plans to pay $30 million to producers whose leases will be cancelled in areas set aside for conservation. Oil and gas companies will be allowed to continue to operate in conservation and recreation areas while oil sands companies' tenures will be cancelled.  New petroleum and gas tenure sold in conservation areas will include a restriction that prohibits surface access.  Application procedures for activities and facilities in the LARP, regulated by the Energy Resources Conservation Board and the Alberta Utilities Commission, respectively, have been changed to accommodate the new restrictions set out in the LARP.  The LARP is the first of seven regions to get a land use plan.  The next will be the South Saskatchewan region.
  In British Columbia, the Oil and Gas Activities Act (the "OGCA") impacts conventional oil and gas producers, shale gas producers, and other operators of oil and gas facilities in British Columbia. Under the OGCA, the British Columbia Oil and Gas Commission has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for oil and gas activities. The Environmental Protection and Management Regulation establishes the government’s environmental objectives for water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGCA requires the Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity.  In addition, although not an exclusively environmental statute, the Petroleum and Natural Gas Act requires proponents to obtain various approvals before undertaking exploration or production work, such as geophysical licences, geophysical exploration project approvals, and permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole, and water-source well authorizations. Such approvals are given subject to environmental considerations and licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.
  In May of 2011, Saskatchewan passed changes to The Oil and Gas Conservation Act ("SKOGCA"), the act governing the regulation of resource development operations in the province. Although the associated Bill received Royal Assent on May 18, 2011, it was not proclaimed into force until April 1, 2012, in conjunction with the release of The Oil and Gas Conservation Regulations, 2012 ("OGCR") and The Petroleum Registry and Electronic Documents Regulations ("Registry Regulations").  The aim of the amendments to the SKOGCA, and associated regulations, is to provide resource companies investing in Saskatchewan's energy and resource industries with the best support services and business and regulatory systems available.  With the enactment of the Registry Regulations and the OGCR, Saskatchewan has implemented a number of operational aspects, including the increased demand for record-keeping, increased testing requirements for injection wells and increased investigation and enforcement
 
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 powers; and, procedural aspects including those related to Saskatchewan’s participation as partner in the Petroleum Registry of Alberta.
  Climate Change Regulation
  Federal
  On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both greenhouse gases ("GHGs") and air pollution.  An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan").  The Updated Action Plan outlines emissions intensity-based targets, which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis.  Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors.  Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets. Although the intention was for draft regulations for the implementation of the Updated Action Plan to become binding on January 1, 2010, the only regulations announced pertain to carbon dioxide emissions from coal-fired generation of electricity (finalized in summer 2012).  Further, representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation.  As a result, it is unclear to what extent implementation of the proposals contained in the Updated Action Plan will occur.
  The United States Environmental Protection Agency (the "EPA") has indicated its intention to impose GHG emissions standards for fossil fuel-fired power plants by specifying that it would issue final regulations by May 26, 2012, and with respect to refineries, specifying that it will issue proposed regulations by December 10, 2011 and finalized regulations by November 10, 2012.  The EPA did not meet the December 10, 2011 deadline and it is unclear whether the EPA will also miss the finalized regulations deadline.  However, in March 2012, the EPA proposed a strict GHG standard on new power plants only.  While it is expected that this rule could encourage building new natural gas power plants rather than coal plants, the actual effect of the new rule will not be able to be quantified for some time.
  Alberta
  Alberta enacted the Climate Change and Emissions Management Act(the "CCEMA") on December 4, 2003, amending it through the Climate Change and Emissions Management Amendment Actwhich received royal assent on November 4, 2008.  The CCEMA is based on an emissions intensity approach and aims for a 50 per cent reduction from 1990 emissions relative to GDP by 2020.
  Alberta facilities emitting more than 100,000 tonnes of GHGs per year are subject to compliance with the CCEMA.  Similar to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation make a distinction between "Established Facilities" and "New Facilities".  Established Facilities are defined as facilities that completed their first year of commercial operation prior to January 1, 2000 or that have completed eight or more years of commercial operation.  Established Facilities are required to reduce their emissions intensity to 88 per cent of their baseline for 2008 and subsequent years, with their baseline being established by the average of the ratio of the total annual emissions to production for the years 2003 to 2005.  New Facilities are defined as facilities that completed their first year of commercial operation on December 31, 2000, or a subsequent year, and have completed less than eight years of commercial operation, or are designated as New Facilities in accordance with the Specified Gas Emitters Regulation.  New Facilities are required to reduce their emissions intensity by two per cent from baseline in the fourth year of commercial operation, four per cent of baseline in the fifth year, six per cent of baseline in the sixth year, eight per cent of baseline in the seventh year, and 10 per cent of baseline in the eighth year.  Unlike the Updated Action Plan, the CCEMA does not contain any provision for continuous annual improvements in emissions intensity reductions beyond those stated above.
  The CCEMA contains several compliance mechanisms.  Regulated emitters can meet their emissions intensity targets by contributing to the Climate Change and Emissions Management Fund at a rate of $15 per tonne of CO2 equivalent, they can reduce their emissions through in-house reductions, or they can purchase emissions credits from regulated emitters that have reduced their emissions below their emission intensity target or non-regulated emitters that have generated emissions offsets through activities that result in emissions reductions in accordance with established protocols published by the Government of Alberta.  As a non-regulated entity, ARC is able to consider engaging in the Alberta carbon offset market as a net-seller of offsets in accordance with the CCEMA.
  On December 2, 2010, the Government of Alberta passed theCarbon Capture and Storage Statutes Amendment Act, 2010.  It deemed the pore space underlying all land in Alberta to be and to have always been the property of the
 
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  Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.
  British Columbia
  In February 2008, British Columbia announced a revenue-neutral carbon tax that took effect July 1, 2008.  The tax is consumption-based and applied at the time of retail sale or consumption of virtually all fossil fuels purchased or used in British Columbia.  The current tax level is $30 per tonne of CO2 equivalent.  The final scheduled increase took effect on July 1, 2012. There is no plan for further rate increases or expansions at this time.  In order to make the tax revenue-neutral, British Columbia has implemented tax credits and reductions in order to offset the tax revenues that the Government of British Columbia would otherwise receive from the tax.
  In their 2012 Budget, British Columbia announced the government will undertake a comprehensive review of the carbon tax and its impact on British Columbians. The review will cover all aspects of the carbon tax, including revenue neutrality, and will consider the impact on the competitiveness of British Columbia businesses such as those in the agriculture sector, and in particular, British Columbia’s food producers. Under this comprehensive review, British Columbians can make written submissions to British Columbia’s Minister of Finance, and these will be considered as part of the 2013 Budget process.
  On April 3, 2008, British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the "Cap and Trade Act") which received royal assent on May 29, 2008 and partially came into force by regulation of the Lieutenant Governor in Council.  It sets a province-wide target of a 33 per cent reduction in the 2007 level of GHG emissions by 2020 and an 80 per cent reduction by 2050.  Unlike the emissions intensity approach taken by the federal government and the Government of Alberta, the Cap and Trade Act establishes an absolute cap on GHG emissions.  The Cap and Trade Act sets out the requirements for the reporting of the greenhouse gas emissions from facilities in British Columbia emitting 10,000 tonnes or more of carbon dioxide equivalent emissions per year beginning on January 1, 2010. Those reporting operations with emissions of 25,000 tonnes or greater are required to have emissions reports verified by a third party. Recent amendments to the Act repealed past requirements on public-sector organizations, including Crown corporations, to be carbon neutral by 2010, and they are now only required to produce annual carbon reduction plans and reports.  Additional regulations that will further enable British Columbia to implement a cap and trade system are currently under further development.
  Saskatchewan
  On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act(the "MRGGA") to regulate GHG emissions in the province.  The MRGGA received Royal Assent on May 20, 2010 and will come into force on proclamation.  Regulations under the MRGGA have also yet to be proclaimed, but draft versions indicate that Saskatchewan will adopt the goal of a 20 per cent reduction in GHG emissions from 2006 levels by 2020.
  Manitoba
  The Government of Manitoba has commenced public consultations with respect to the development of a cap and trade system to reduce GHG emissions; however, no legislation is currently in effect in Manitoba.  In June 2007, Manitoba joined the Western Climate Initiative ("WCI"), which was established to identify, evaluate and implement collective, co-operative ways to reduce greenhouse gases within a specified region.  The regional partners who form the WCI, focus on a market based cap and trade system, and additional reduction opportunities through complementary measures.  WCI regional partners include seven U.S. states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces (British Columbia, Manitoba, Ontario and Québec).  The WCI's goal is to reduce GHG emissions in the region by 15 per cent below 2005 levels, by 2020.  When fully implemented in 2015, the WCI aims to cover nearly 90 per cent of the region's emissions.
  RISK FACTORS
  The following is a summary of certain risk factors relating to our business which prospective investors should carefully consider before deciding whether to purchase Common Shares.  Residents of the United States and other non-residents of Canada should have additional regard to the risk factors under the heading "Risk Factors Applicable to Residents of the United States and Other Non-Residents of Canada".
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 Risks Relating to Our Business and Operations
  Declines in oil and natural gas prices will adversely affect our financial condition
  Our operational and financial results will be dependent on the prices received for oil and natural gas production.  Oil and natural gas prices respond to supply/demand imbalances and can be volatile. For example, the price of AECO natural gas for the year ended December 31, 2012 was $2.40 per Mcf down from $3.67 per Mcf for the year ended December 31, 2011, a 35 per cent decline.
  Oil and natural gas prices are determined by supply and demand and in the case of oil prices, political factors and a variety of additional factors beyond our control.  These factors include economic conditions, both in North America and worldwide, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability, the increased capacity to bring new production on stream due to technology such as multi-stage fracturing, the foreign supply of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources.  North America has an abundance of natural gas reserves, primarily as a result of advancements in hydraulic fracturing techniques. Natural gas prices are impacted by North American inventory levels which have improved year over year but are still significantly above the five year average.
  Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the carrying value of our proved and probable reserves, net asset value, borrowing capacity, production, revenues, profitability and funds from operations, levels of capital expenditures and ultimately on our financial condition and therefore on the dividends to be paid to our Shareholders.
  Gathering and processing facilities and pipeline systems are subject to certain risks and in certain circumstances may adversely affect the amounts realized by us for our oil and natural gas
  We deliver our products through gathering, processing and pipeline systems some of which we do not own.  The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. During much of 2012, increases in Canadian and United States oil supply, higher than normal refinery outages, and United States pipeline bottlenecks resulted in significantly lower crude oil prices being realized by Canadian producers compared to the WTI price for crude oil.  This price decrease could result in the our inability to realize the full economic potential of our crude oil production.  Although the transportation of crude oil by pipeline, rail car and by barge is expanding, the lack of firm transportation capacity continues to affect the oil industry and limit the ability to produce and to market oil production.  In addition, the pro-rationing of capacity on inter-provincial pipeline systems also continues to affect the ability to export oil.  Even though there are currently no restrictions on the flow of natural gas in North America, future pipeline restrictions may occur. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm our business and, in turn, our financial condition, results of operations and funds from operations.
  Due to aging infrastructure, certain pipeline leaks have gained media, environmental and other stakeholder attention.  This attention may result in additional regulation or changes in law which could impede the conduct of our business or make our operations more expensive.
  A portion of our production is processed through facilities owned by third parties that which we do not have control of.  From time-to-time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events.  A discontinuance or decrease of operations could adversely affect our ability to process our production and to deliver the same for sale.
  Increases in the value of the Canadian dollar against the U.S. dollar may adversely affect our financial condition
  World oil prices are quoted in US dollars and the price received by Canadian producers is therefore affected by the Canadian/US dollar exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our net production revenue.
  Global economic events may negatively impact our financial condition
  Market events and conditions, including disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels, may cause significant volatility to commodity prices and a decline in funds from operations.  Global economic events and conditions may cause a loss of confidence in the broader global credit and financial markets and create a climate of greater volatility, less liquidity, wider credit spreads, a lack
 
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 of price transparency, increased credit losses and tighter credit conditions.  Market events in the future may affect our ability to obtain equity or debt financing on acceptable terms and may make it more difficult to operate effectively.
  The Board of ARC Resources has discretion in the payment of dividends and may not choose to maintain the payment of dividends in certain circumstances
  Dividends on the Common Shares are not preferential, nor cumulative nor stipulated by their terms to be at a fixed amount or rate.  As such dividends do not represent a "yield" in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments.  Dividends are conditionally declared by our Board in its sole discretion and are subject to confirmation by a monthly press release and are specifically subject to change in accordance with our dividend policy.  The dividend policy is also subject to change in the sole discretion of our Board of Directors.  See "Dividends and Distributions – Dividend Policy".  Dividends may be varied or discontinued at any time.
  Our ability to maintain dividend payments is dependent on a number of factors including our success in exploiting existing properties and acquiring additional reserves as producing properties decline over time
  Our ability to add to our oil and natural gas reserves is highly dependent on our success in exploiting existing properties and acquiring additional reserves.  The production from individual wells and properties declines over time.  We currently distribute a proportion of our funds from operations, by way of dividend payments, to Shareholders rather than reinvesting it in reserves additions.  Our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be dependent on the level of our funds from operations and external sources of capital.  There is no assurance we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives.  Without these reserves additions, our reserves will deplete and as a consequence, either production from, or the average reserves life of, our properties will decline, which may result in a reduction in the value of Common Shares and in a reduction in funds from operations available for the payment of dividends to Shareholders.
  Our hedging activities may negatively impact our income and the financial condition of the Corporation.
  We actively manage the risk associated with changes in commodity prices by entering into oil and natural gas price hedges.  If we hedge our commodity price exposure, we will forego some of the benefits we would otherwise experience if commodity prices were to increase, and some of these foregone benefits may be material relative to funds from operations.  For more information in relation to our commodity hedging program, see "Statement of Reserve Data and Other Oil and Gas Information – Forward Contracts".  We also may initiate certain hedges to attempt to mitigate the risk of the Canadian dollar appreciating against the U.S. dollar.  The increase in the exchange rate for the Canadian dollar and future Canadian/United States exchange rates may impact future funds from  operations, dividend payments and the future value of our reserves as determined by independent evaluators.  These hedging activities could expose us to losses, which may be material, and to credit risk associated with counterparties with whom we contract.
  Our business is heavily regulated including through the payment of royalties and such regulation increases our costs and may adversely affect our financial condition
  Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including land tenure, exploration, development, production, refining, transportation and marketing).  In particular, most of our oil and natural gas assets are subject to royalties imposed by the governments of British Columbia, Alberta, Saskatchewan and Manitoba which are subject to variation by such governments.  Governments may regulate or intervene with respect to exploration and production activities, price, taxes, royalties and the exportation of oil and natural gas.  In order to conduct oil and gas operations, we require licenses from various governmental authorities.  There can be no assurance that we will be able to obtain all of the licenses and permits that may be required to conduct operations that we may wish to undertake.  See "Industry Conditions".
  Our success depends in large measure on certain key personnel and our ability to retain our key personnel
  The loss of our key personnel could delay the completion of certain projects or otherwise have a material adverse effect on us.  Shareholders will be dependent on our management and staff in respect of the administration and management of all matters relating to our properties, the Common Shares and the safekeeping of our primary workspace and computer systems.  Any deterioration of our corporate culture could adversely affect our long-term success.
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 Our bank credit facility is subject to renewal, compliance and covenants
  We currently have a $1 billion syndicated credit facility with twelvebanks which was undrawn as at December 31, 2012.  The maturity date of the facility is currently August 3, 2016.  The terms of the credit facility allow for annual renewals at the request of ARC and at the discretion of the lenders.   At December 31, 2012, ARC had $787.4 million of long-term debt outstanding in the form of Long-Term Notes ("Notes").  The Notes are repayable over the next twelve years. We intend to fund these repayments with existing credit facilities and/or with proceeds from additional note issuances.
  Although we believe the credit facilities will be sufficient for our immediate requirements, there can be no assurance that the amount will be adequate for our future financial obligations including our future capital expenditure programs, that additional funds will be able to be obtained or that we will be able to extend or renew our credit facilities.
  We are required to comply with covenants under the credit facility and under our U.S. and Canadian denominated long-term notes.  In the event that we do not comply with covenants under the credit facility and our long-term notes, our access to capital could be restricted or repayment could be required on an accelerated basis by our lenders, and the ability to pay dividends to our Shareholders may be restricted.
  Variations in interest rates and scheduled principal repayments could result in changes in the amount required to be applied to debt service resulting in a decrease in the amount available for payment of dividends on the Common Shares.  Certain covenants of the agreements with our lenders may also limit the payment of dividends.  For more information, see "Other Information Relating to Our Business – Borrowing".
  We have been historically reliant on external sources of capital, borrowings and equity sales, and if unavailable, our financial condition could be adversely affected
  We anticipate making substantial capital expenditures for the development of oil and natural gas reserves in the future.  Other capital expenditures may also include exploration, undeveloped land and acquisitions from time to time. Future capital expenditures will be financed out of funds from operations, borrowings, property dispositions and possible future equity issuances; however, our ability to do so is dependent on, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry and our securities in particular.  Further, if our revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future drilling programs.
  Alternatively, we may issue additional Common Shares from treasury at prices which may result in a decline in production per Common Share and reserves per Common Share or we may wish to borrow to finance significant acquisitions or development projects to accomplish our long-term objectives on less than optimal terms or in excess of our optimal capital structure.
  To the extent that external sources of capital become limited or unavailable or available on onerous terms, our ability to make capital investments and maintain or expand existing assets and reserves may be impaired, and our assets, liabilities, business, financial condition, results of operations and dividend payments may be materially and adversely affected as a result.
  From time-to-time we may enter into transactions to acquire assets or shares of other organizations.  These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of similar size.  Depending on future exploration and development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms.  The level of our indebtedness from time-to-time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise
  Failure of third parties to meet their contractual obligations to us may have a material adverse effect on our financial condition
  We are exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, third party operators, purchasers of our petroleum and natural gas production and other parties.  Poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until we find a suitable alternative partner.
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 Income tax laws, or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders
  The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia, Saskatchewan and Manitoba, all of which should be carefully considered by investors in the oil and gas industry.  All of such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have historically been material and in some cases materially adverse and there can be no assurance that there will not be further revocation, amendment or administrative change which will be materially adverse to our assets, reserves, financial condition or results of operations or prospects and our ability to maintain the payment of dividends.
  Income tax laws, other laws or government incentive programs relating to the oil and gas industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders.  Tax authorities having jurisdiction over us or Shareholders may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment or the detriment of Shareholders.
  There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves and resources including many factors beyond our control
  In general, estimates of economically recoverable oil and natural gas reserves and resources, the future net revenues and finding and development costs are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.
  The reserves and recovery information and the resource information contained in the GLJ Report is only an estimate and the actual production and ultimate reserves and resources from the properties may be greater or less than the estimates prepared by GLJ.  The GLJ Report has been prepared using certain commodity price assumptions (see “Statement of Reserves Data and Other Oil and Gas Information – Forecast Prices and Costs).  If we realize lower prices for crude oil, natural gas liquids and natural gas and they are substituted for the price assumptions utilized in those reserves reports, the present value of estimated future net revenues for our reserves and net asset value would be reduced and the reduction could be significant.  The estimates in the GLJ Report are based in part on the timing and success of activities we intend to undertake in future years.  The reserves and estimated future net revenues contained in the GLJ Report will be reduced in future years to the extent that such activities do not achieve the production performance set forth in the GLJ Report.
  Estimates of proved undeveloped reserves are sometimes based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history.  Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools.  Estimates based on these methods are generally less reliable than those based on actual production history.  Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.
  Estimates of Economic Contingent Resources contained in the GLJ Report are subject to the definitions, disclaimers, contingencies and warnings set forth under the heading "Statement of Reserves Data and Other Oil and Gas Information – Contingent Resource Estimates".  There is no certainty that it will be commercially viable to produce any portion of the resources.
  Increases in interest rates may adversely affect our financial condition
  There is a risk that interest rates will increase.  Current interest rates are low compared to historical levels.  An increase in interest rates may result in an increase in the amount we pay to service debt, resulting in a decrease in funds from operations.  This could affect dividends to Shareholders and the market price of the Common Shares. Further, the value of our Common Shares may decline in an environment of increasing interest rates as investors’ rate of return expectations may be higher.
  Hydraulic fracturing is subject to certain risks
  Hydraulic fracturing can be performed utilizing a number of methods but typically involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate hydrocarbon (natural gas and oil) production.  The use of hydraulic fracturing is being used to produce commercial quantities of natural gas and oil from
 
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 reservoirs that were previously unproductive.  We use hydraulic fracturing extensively in our operations.  With the increase in the use of fracture stimulations in horizontal wells there is increased communication between the oil and natural gas industry and a wider variety of stakeholders regarding the responsible use of this technology as it relates to the environment.  This increased attention to fracture stimulations may result in increased regulation or changes of law which may make the conduct of our business more expensive or prevent us from conducting our business as currently conducted.  Any new laws, regulation or permitting requirements regarding hydraulic fracturing could lead to operational delay or increased operating costs or third party or governmental claims, and could increase our costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations which are not commercial without the use of hydraulic fracturing.  Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves and could materially reduce both the volume and the value of our reserves.
  Acquiring, developing and exploring for oil and natural gas involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome
  These risks include, but are not limited to, encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires, spills and delays in payments between parties caused by operation or economic matters.  These risks will increase as we undertake more exploratory activity.  Drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells.  These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.  Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks.  In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons.  The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on our business, financial condition, results of operations and prospects.
  Continuing production from a property, and to some extent the marketing of production, are largely dependent upon the ability of the operator of the property.  Other companies operate some of the properties in which we have an interest and as a result our returns on assets operated by others depends upon a number of factors outside our control.  To the extent the operator fails to perform these functions properly, operating income may be reduced.
  Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to maintain the payment of dividends.
  We are participating in larger projects and have more concentrated risk in certain areas of our operations
  We manage a variety of small and large projects in the conduct of our business.  We have undertaken large development projects, including the construction of gas processing plants, in northeastern British Columbia for the development of our natural gas reserves.  Project delays may impact expected revenues from operations.  Significant project cost over-runs could make a project uneconomic.  Our ability to execute projects and market oil and natural gas depends upon numerous factors beyond our control, including:
  —
the availability of processing capacity;
 —
the availability and proximity of pipeline capacity;
 —
the availability of storage capacity;
 —
the availability of, and the ability to acquire, water supplies needed for drilling and hydraulic fracturing, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental regulations;
 —
the supply of and demand for oil and natural gas;
 —
the availability of alternative fuel sources;
 —
the effects of inclement weather;
 —
the availability of drilling and related equipment;
 —
unexpected cost increases;
 —
accidental events;
 —
changes in regulations;
 —
the availability and productivity of skilled labour; and
 —
the regulation of the oil and natural gas industry by various levels of government and governmental agencies.
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 Because of these factors, we could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.
  We only operate in western Canada and expansion outside of these areas may increase our risk exposure
  Our operations and expertise are currently focused on oil and gas production and development in the Western Canadian Sedimentary Basin.  In the future, we may acquire oil and gas properties outside this geographic area.  In addition, we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines, or an interest in an oil sands project.  Expansion of our activities into new areas may present new additional risks or alternatively, significantly increase the exposure to one or more of the present risk factors which may adversely affect our future operational and financial conditions.
  We may not be able to realize the anticipated benefits of acquisitions and dispositions
  The price we pay for the purchase of any material properties is based on engineering and economic estimates of the reserves made by management and independent engineers modified to reflect our technical and economic views.  These assessments include a number of material factors and assumptions.  Consequently, the reserves acquired may be less than expected, which could adversely impact funds from operations and the payment of dividends to Shareholders.
  We make acquisitions and dispositions of businesses and assets in the ordinary course of business.  Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation.  There is no assurance that we will be able to continue to complete acquisitions or dispositions of oil and natural gas properties which realize all the synergistic benefits expected.
  Climate change laws and related environment regulation may impose restrictions or impose costs on our business which may adversely affect our financial condition and our ability to maintain distributions
  The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation.  A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of us or our properties, some of which may be material.  Furthermore, management believes the political climate appears to favour new programs for environmental laws and regulation, particularly in relation to the reduction of emissions or emissions intensity, and there is no assurance that any such programs, laws or regulations, if proposed and enacted, will not contain emission reduction targets which we cannot meet, and financial penalties or charges could be incurred as a result of the failure to meet such targets.  For more information on the evolution and status of climate change and related environmental legislation, see "Industry Conditions – Climate Change Regulation".
  There has been much public debate with respect to the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases.  Implementation of strategies by either the provinces in which we operate our business or by the Government of Canada, and whether to meet international agreed limits, or as otherwise determined, for reducing greenhouse gases could have a material impact on the nature of oil and natural gas operations, including ours.  Climate change policy is evolving at regional, national and international levels and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place.  As a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") and as a participant to the Copenhagen Agreement (a non-binding agreement created by the UNFCCC), the Government of Canada announced on January 29, 2010 that it will seek a 17 per cent reduction in greenhouse gas ("GHG") emissions from 2005 levels by 2020.  These GHG emission reduction targets are not binding, however.  Although it is not the case today, some of our significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions.  Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on us and our operations and financial condition.
  Provincial regulation requires the reclamation and abandonment of wells at the end of their production life.  We have established a reclamation fund for the purpose of funding our currently estimated future environmental and reclamation obligations for our assets at Redwater.  We have not established a reclamation fund for any of our other assets.  There can be no assurance that we will be able to satisfy our actual future environmental and reclamation obligations for our assets at Redwater or elsewhere.
  Although we believe that we are in material compliance with current applicable environmental regulations, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition,
 
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 results of operations or prospects.  Future changes in other environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition or results of operations and prospects.  See "Industry Conditions – Climate Change Regulation".
  There is strong competition relating to all aspects of the oil and gas industry
  There are numerous companies in the oil and gas industry, who are competing with us for the acquisitions of properties, properties with exploitation and development opportunities and undeveloped land.  As a result of such competition, it may be more difficult for us to acquire reserves on beneficial terms.  Many of these other oil and gas companies have significantly greater financial and other resources than we do.
  Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted.  Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities.
  We compete with other oil and gas entities to hire and retain skilled personnel necessary for our daily operations including planning, realizing on available technical advances and the execution of the annual capital development program.  The inability to hire and retain skilled personnel could adversely impact certain of our operational and financial results.
  Application of accounting policies could result in non-cash losses which may adversely affect the market price of our Common shares
  Our accounting policies conform to International Financial Reporting Standards ("IFRS") which constitutes generally accepted accounting principles in Canada.  IFRS may result in non-cash charges and/or write-downs of net assets in the financial statements.  Such non-cash charges and write-downs under IFRS may be viewed unfavourably by the market and may result in an inability to borrow funds and/or may result in a decline in the price of the Common Shares.
  IFRS requires that impairment testing be performed at a producing unit level.  Under IFRS, if net capitalized costs of the producing unit exceed the estimated net recoverable value of the reserves at a producing unit level, the excess amount is charged to earnings.  Under IFRS, write-downs may be reversed in a subsequent period if there is an increase in the net recoverable value of the reserves at the producing unit level.  As a result, there is risk of volatile earnings relating to impairment testing under IFRS.
  IFRS requires that expenditures that meet the definition of exploration activities be classified and assessed separately for impairment.  If such exploration activities are deemed to be "unsuccessful", the related expenditures must be written-off against earnings.  As a result, there may be frequent write-downs and in turn volatile earnings relating to exploration expenditures under IFRS.
  IFRS requires that gains and losses on sale of properties be recorded through earnings when realized.  As a result, there may be volatile earnings relating to gains and losses on sale of assets under IFRS.
  Under IFRS, the accounting for derivatives may result in non-cash charges against net income as a result of changes in the fair market value of derivative instruments.  A decrease in the fair market value of the derivative instruments as the result of fluctuations in commodity prices and foreign exchange rates may result in a write-down of net assets and a non-cash charge against net income.  Such write-downs and non-cash charges may be temporary in nature if the fair market value subsequently increases.
  For more information as to other future accounting changes, see the section in our Management's Discussion and Analysis for the year ended December 31, 2012 under the heading "Financial Reporting Update – Future Accounting Changes" which section is incorporated in this Annual Information Form by reference and is found on our SEDAR profile at www.sedar.com.
  Securing and maintaining title to our properties is subject to certain risks
  Our properties are held in the form of licenses and leases and working interests in licenses and leases.  If we or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire.  There can be no assurance that any of the obligations required to maintain each license or lease will be met.  The termination or expiration of a license or lease or the working interest relating to a license or lease
 
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 may have a material adverse effect on our results of operations and business.  In addition title to the properties can become subject to dispute and defeat our claim to title over certain of our properties.  Furthermore, there may be legislative changes which affect title, to the oil and natural gas properties we control that, if successful or made into law, could impair our activities on them and result in a reduction of the revenue received by us.
  Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada.  We are not aware that any material claims have been made in respect of our properties and assets; however, if a claim arose and was successful this could have an adverse effect on us and our operations.
  Risk Factors Applicable to Residents of the United States and Other Non-Residents of Canada
  There is limited ability of residents in the United States to enforce civil remedies
  ARC Resources is a corporation formed under the laws of Alberta, Canada and has its principal place of business in Canada.  All of our directors and all of our officers and the representatives of the experts who provide services to us (such as our auditors and our independent reserve engineers), and all of our assets and all or a substantial portion of the assets of such persons are located outside the United States.  As a result, it may be difficult for investors in the United States to effect service of process within the United States upon such directors, officers and representatives of experts who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States.  There is doubt as to the enforceability in Canada against ARC Resources or against any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.
  There are differences in reporting practices in Canada and the United States
  We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101.  These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the Securities Exchange Commission by companies in the United States.
  We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the Securities Exchange Commission and practices in the United States.  We follow the Canadian practice of reporting gross production and reserve volumes (before deduction of Crown and other royalties); however, we also follow the United States practice of separately reporting reserve volumes on a net basis (after the deduction of royalties and similar payments).  We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves; whereas the Securities Exchange Commission requires that prices and costs be averaged for the 12 months prior to the date of the reserve report.
  We included in this Annual Information Form estimates of proved and proved plus probable reserves.  Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves.  The Securities Exchange Commission generally prohibits the inclusion of estimates of probable reserves in filings made with it.  This prohibition does not apply to us because we are a Canadian foreign private issuer.
  We have included in the Annual Information Form estimates of Economic Contingent Resources.  Economic Contingent Resources are a class of resources and should not be confused with reserves and are subject to the definitions, disclaimers and warnings set forth under the heading "Statement of Reserves Data and Other Oil and Gas information – Contingent Resource Estimates".  The Securities Exchange Commission prohibits the inclusion of Contingent Resource estimates in filings made with it.  This prohibition does not apply to us because we are a Canadian foreign private issuer.
  As a consequence of the foregoing, our reserve estimates and production volumes in this Annual Information Form may not be comparable to those made by companies utilizing United States reporting and disclosure standards.
  There is additional taxation applicable to dividends paid to non-residents
  Cash dividends paid to a non-resident of Canada on Common Shares are subject to Canadian withholding tax at a rate of 25 per cent unless the rate is reduced under the provisions of an applicable double taxation treaty.  Where a non-resident is a United States resident entitled to benefits of the Canada – United States Income Tax Convention,
 
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 1980 and is the beneficial owner of the dividends then the rate of Canadian withholding tax is generally reduced to 15 per cent.
  There is a foreign exchange risk to non-resident Shareholders
  Our dividends are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment.  As a consequence, investors are subject to foreign exchange risk.  To the extent that the Canadian dollar strengthens with respect to their currency, the amount of the dividend will be reduced when converted to their home currency.
  TRANSFER AGENT AND REGISTRAR
  The transfer agent and registrar for the Common Shares is Computershare Trust Company of Canada at its principal offices in Calgary and Toronto.
  MATERIAL CONTRACTS
  The following comprises particulars of every material contract of ARC that was entered into within the most recently completed financial year, or entered into before the most recently completed financial year which is still in effect, other than a contract entered into in the ordinary course of business:
  1.
Amended and Restated Credit Agreement dated as of August 4, 2010 between ARC Resources and a syndicate of lenders, and an administrative agent, as amended January 1, 2011, and September 26, 2011 providing for an extendible revolving credit facility up to Cdn $1 billion.  The maturity date of the facility was extended for an additional year to August 3, 2016 under the existing terms on October 22, 2012.
  2.
Amended and Restated Uncommitted Master Shelf Agreement as of December 15, 2005 between ARC Resources and various purchasers, as amended on May 17, 2006, April 14, 2009, February 22, 2010,  January 1, 2011 and April 14, 2012 providing for the issuance and sale of up to an aggregate principal amount of US $225 million in notes of which US $46.9 million 5.42% Series C Notes due December 15, 2017 and US $50 million 4.98% Series D Notes due March 5, 2019 are currently outstanding.
  3.
Note Purchase Agreement dated as of April 27, 2004 between ARC Resources and various purchasers, as amended on April 14, 2009, March 31, 2010 and January 1, 2011, with respect to US $62.5 million 4.62% Series A Notes due April 27, 2014 and US $62.5 million 5.10% Series B Notes due April 27, 2016 of which US $12.8 million and US $19.2 million, respectively, are currently outstanding.
  4.
Note Purchase Agreement dated as of April 14, 2009 between ARC Resources and various purchasers, as amended January 1, 2011 with respect to US $67.5 million 7.19% Series C Notes due April 14, 2016, US $35 million 8.21% Series D Notes due April 14, 2021 and Cdn $29 million 6.50% Series E Notes due April 14, 2016 of which US $54.0 million, US $35.0 million and Cdn $23.2 million, respectively, are currently outstanding.
  5.
Note Purchase Agreement dated as of May 27, 2010 between ARC Resources and various purchasers, as amended January 1, 2011 with respect to US $150 million 5.36% Series F Notes due May 27, 2022.
  6.
Note Purchase Agreement dated as of August 23, 2012 between ARC Resources and various purchasers with respect to US $60.0 million 3.31% Series G Notes due August 23, 2021, US $300 million 3.81% Series H Notes due August 23, 2024 and Cdn $40.0 million Series I Notes due August 23, 2024.
  For more information in relation to these material contracts, see "Other Information Relating to Our Business – Borrowings".  Copies of each of these documents have been filed on our SEDAR profile at www.sedar.com.
  INTEREST OF EXPERTS
  There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by us during, or related to, our most recently completed financial year other than GLJ, our independent engineering evaluator, and Deloitte LLP, our auditors.  As at the date hereof the designated professionals of GLJ, as a group, beneficially owned, directly or indirectly, less than one per cent of our outstanding securities, including the securities of our associates and affiliates.  Deloitte LLP is the
 
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 auditor of ARC Resources and is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.
  In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of ARC Resources or of any of our associate or affiliate entities.  Allan R. Twa, the Corporate Secretary of ARC Resources, is a partner of Burnet, Duckworth & Palmer LLP, which law firm renders legal services to us.
  ADDITIONAL INFORMATION
  Additional information including remuneration and indebtedness of directors and officers of ARC Resources, principal holders of the Common Shares and options to purchase Common Shares, is contained in the Information Circular - Proxy Statement of the Corporation which relates to the Annual and Special Meeting of Shareholders to be held on May 15, 2013.  Additional financial information is provided in our consolidated financial statements and accompanying management's discussion and analysis for the year ended December 31, 2012, which have been filed on our SEDAR profile at www.sedar.com.  Other additional information relating to us may be found on our SEDAR profile at www.sedar.com.
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 APPENDIX A
 FORM 51-101F2
  REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
  To the board of directors of ARC Resources Ltd. (the "Company"):
  1.
We have evaluated the Company's reserves data as at December 31, 2012.  The reserves data are estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2012, estimated using forecast prices and costs.
  2.
The reserves data are the responsibility of the Company's management.  Our responsibility is to express an opinion on the reserves data based on our evaluation.
  We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
  3.
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement.  An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
  4.
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed total proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us for the year ended December 31, 2012, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:
  IndependentQualified

ReservesEvaluator

Description andPreparation Date

of EvaluationReport

Location of  Reserves

(Country orForeign

GeographicArea)

Net Present Value of Future Net Revenue

(before income taxes, 10% discount rate,

$millions)Audited


Evaluated


Reviewed


TotalGLJ Petroleum

Consultants Ltd.

Corporate

Evaluation

January 15, 2013

Canada


-



6,039



-



6,039
  5.
In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.
  6.
We have no responsibility to update our report referred to in paragraph 4 for events and circumstances occurring after its preparation date.
  7.
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
  Executed as to our report referred to above:
  GLJ Petroleum Consultants Ltd.

Calgary, Alberta, Canada





(signed) "Bryan M. Joa"

Bryan M. Joa, P.Eng

Vice President
Dated February 20, 2013
  
 Table of Contents
  APPENDIX B
 FORM 51-101F3
  REPORT OF MANAGEMENT AND DIRECTORS ON
 RESERVES DATA AND OTHER INFORMATION
  Management of ARC Resources Ltd. (the "Company") is responsible for the preparation and disclosure of information with respect to the Company's and its subsidiaries' oil and gas activities in accordance with securities regulatory requirements.  This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2012 estimated using forecast prices and costs.
  An independent qualified reserves evaluator has evaluated the Company's and its subsidiaries' reserves data.  The report of the independent qualified reserves evaluator is presented below.
  The Reserves Committee of the board of directors of the Company has
  (a)
reviewed the Company's procedures for providing information to the independent qualified reserves evaluator;
  (b)
met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and
  (c)
reviewed the reserves data with management and the independent qualified reserves evaluator.
  The Reserves Committee of the board of directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management.  The board of directors has, on the recommendation of the Reserves Committee, approved
  (d)
the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
  (e)
the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and
  (f)
the content and filing of this report.
  Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
  (signed) "Myron Stadnyk"
(signed) "Cameron Kramer"Myron Stadnyk
Cameron KramerPresident and Chief Executive Officer
Senior Vice-President and Chief Operating Officer(signed) "James Houck"
(signed) "Fred J. Dyment"James Houck
Fred J. DymentDirector and Chairof the Reserves Committee
Director and Member of the Reserves CommitteeMarch 20, 2013
 
 
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 APPENDIX C
  MANDATE OF THE AUDIT COMMITTEE
  Role and Objective
  The Audit Committee (the "Committee") is a committee of the Board of Directors of ARC Resources Ltd. (the "Corporation") to which the Board has delegated its responsibility for oversight of the nature and scope of the annual audit, management's reporting on internal accounting standards and practices, financial information and accounting systems and procedures, financial reporting and statements and recommending, for Board of Director approval, the audited financial statements and other mandatory disclosure releases containing financial information.  The objectives of the Committee, with respect to the Corporation and its subsidiaries, are as follows:
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To assist Directors to meet their responsibilities in respect of the preparation and disclosure of the financial statements of the Corporation and related matters.
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To provide better communication between Directors and external auditors.
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To ensure the external auditors' independence.
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To review management’s implementation and maintenance of an effective system of internal control over financial reporting and disclosure control over financial reporting.
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To increase the credibility and objectivity of financial reports.
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To facilitate in-depth discussions between directors on the Committee, management and external auditors.
 The primary responsibility for the financial reporting, information systems, risk management and internal and disclosure controls of the Corporation is vested in management and overseen by the Board of Directors of the Corporation.  At each meeting, the Committee may meet separately with management and will meet in separate, closed sessions with the external auditors and then with the independent directors in attendance.
  Mandate and Responsibilities of Committee
  Financial Reporting and Related Public Disclosure
  1.
It is a primary responsibility of the Committee to review and recommend for approval to the Board of Directors the annual and quarterly financial statements of the Corporation.  The Committee is also to review and recommend to the Board of Directors for approval the financial statements and related information included in prospectuses, management discussion and analysis (MD&A), financial press releases, information circular-proxy statements and annual information forms (AIF). The process should include but not be limited to:
  a.
reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years' financial statements;
  b.
reviewing significant management judgments and estimates that may be material to financial reporting including alternative treatments and their impacts;
  c.
reviewing the presentation and impact of any significant risks and uncertainties that may be material to financial reporting including alternative treatments and their impacts;
  d.
reviewing accounting treatment of significant, unusual or non-recurring transactions;
  e.
reviewing adjustments raised by the external auditors, whether or not included in the financial statements;
  f.
reviewing unresolved differences between management and the external auditors;
  g.
determine through inquiry if there are any related party transactions and ensure the nature and extent of such transactions are properly disclosed; and
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  h.
reviewing all financial reporting relating to risk exposure including the identification, monitoring and mitigation of business risk and its disclosure.
  2.
The Committee shall satisfy itself that adequate procedures are in place for the review of the Corporation's public disclosure of financial information from the Corporation's financial statements and periodically assess the adequacy of those procedures.
  Internal Controls Over Financial Reporting and Information Systems
  3.
It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to the Corporation's internal control over financial reporting and information systems.  The process should include but not be limited to:
  a.
inquire as to the adequacy and effectiveness of the Corporation’s system of internal controls over financial reporting and review the evaluation of internal controls over financial reporting by external auditors;
  b.
establish procedures for the confidential, anonymous submission by employees of the Corporation of concerns relating to accounting, internal control over financial reporting, auditing or Code of Business Conduct and Ethics matters and periodically review a summary of complaints and their related resolution; and
  c.
establish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls, or auditing matters.
  External Auditors
  4.
With respect to the appointment of external auditors by the Board, the Committee shall:
  a.
be directly responsible for overseeing the work of the external auditors engaged for the purpose of issuing an auditors' report or performing other audit, review or attest services for the Corporation, including the resolution of disagreements between management and the external auditor regarding financial reporting;
  b.
review the terms of engagement of the external auditors, including the appropriateness and reasonableness of the auditors' fees;
  c.
recommend to the Board appointment of external auditors and the compensation of the external auditors;
  d.
when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change; and
  e.
review and approve any non-audit services to be provided by the external auditors' firm and consider the impact on the independence of the auditors.
  f.
inquire as to the independence of the external auditors and obtain, at least annually, a formal written statement delineating all relationships between the external auditors and the Corporation as contemplated by Independence Standards Board No. 1.
  g.
discuss with the external auditors, without management being present, the quality of the Corporation’s financial and accounting personnel, the completeness and accuracy of the Corporation’s financial statements and elicit comments of senior management regarding the responsiveness of the external auditors to the Corporation’s needs.
  5.
The Committee shall review with the external auditors (and the internal auditor if one is appointed by the Corporation) their assessment of the internal control over financial reporting of the Corporation, their written reports containing recommendations for improvement of internal control over financial reporting and other suggestions as appropriate, and management's response and follow-up to any identified weaknesses.
  6.
The Committee shall also review annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of the Corporation and its subsidiaries.
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  Compliance
  7.
It is the responsibility of the Committee to review management’s process for the certification of annual and interim financial reports in accordance with required securities legislation.
  8.
It is the responsibility of the Committee to ascertain compliance with covenants under loan agreements.
  9.
The Committee shall review the Corporation’s compliance with all legal and regulatory requirements as it pertains to financial reporting, taxation, internal control over financial reporting and any other area the Committee considers to be appropriate relative to its mandate or as may be requested by the Board of Directors.
  Other Matters
  10.
It is the responsibility of the Committee to review and approve the Corporation's hiring policies regarding partners, employees and former partners and employees of the present and external auditors of the Corporation.
  11.
The Committee may also review any other matters that the Audit Committee feels are important to its mandate or that the Board chooses to delegate to it.
  12.
The Committee shall undertake annually a review of this mandate and make recommendations to the Policy and Board Governance Committee as to proposed changes.
  Composition
  13.
This Committee shall be composed of at least three individuals appointed by the Board from amongst its members, all of which members will be independent (within the meaning of National Instrument 52-110 Audit Committees) unless the Board determines to rely on an exemption in NI 52-110.  "Independent" generally means free from any business or other direct or indirect material relationship with the Corporation that could, in the view of the Board, reasonably interfere with the exercise of the member's independent judgment.
  14.
The Chair of the Committee is appointed by the Board of Directors.
  15.
A quorum shall be a majority of the members of the Committee.
  16.
All of the members must be financially literate within the meaning of NI 52-110 unless the Board has determined to rely on an exemption in NI 52-110.  Being "financially literate" means members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Corporation's financial statements.
  Meetings
  17.
The Committee shall meet at least four times per year and/or as deemed appropriate by the Committee Chair.
  18.
The Committee shall meet not less than quarterly with the auditors, independent of the presence of management.
  19.
Agendas, with input from management, shall be circulated to Committee members and relevant management personnel along with background information on a timely basis prior to the Committee meetings.
  20.
The Chief Executive Officer and the Chief Financial Officer or their designates shall be available to attend at all meetings of the Committee upon the invitation of the Committee.
  21.
The Controller, Treasurer and such other staff as appropriate to provide information to the Committee shall attend meetings upon invitation by the Committee.
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  Reporting / Authority
  22.
Following each meeting, in addition to a verbal report, the Committee will report to the Board by way of providing copies of the minutes of such Committee meeting at the next Board meeting after a meeting is held (these may still be in draft form).
  23.
Supporting schedules and information reviewed by the Committee shall be available for examination by any director.
  24.
The Committee shall have the authority to investigate any financial activity of the Corporation and to communicate directly with the internal and external auditors.  All employees are to cooperate as requested by the Committee.
  25.
The Committee may retain, and set and pay the compensation for, persons having special expertise and/or obtain independent professional advice to assist in fulfilling its duties and responsibilities at the expense of the Corporation.